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No securities regulatory authority has expressed an opinion about these securities and it is an offence to claim otherwise. This prospectus constitutesa public offering of securities only in those jurisdictions where such securities may be lawfully offered for sale and therein only by persons permittedto sell such securities. The securities offered hereunder have not been and will not be registered under the United States Securities Act of 1933, asamended (the “U.S. Securities Act”), or the securities laws of any state of the United States and, subject to certain exceptions, may not be offered orsold within the United States except in transactions exempt from registration under the U.S. Securities Act and under the securities laws of eachapplicable state. This prospectus does not constitute an offer to sell or a solicitation of an offer to buy any of the securities offered hereby within theUnited States. See “Plan of Distribution”.

PROSPECTUS

Initial Public Offering November 15, 2010

$210,000,00010,000,000 Common Shares

Tourmaline Oil Corp. (“Tourmaline” or the “Company”) is a Canadian intermediate crude oil and natural gas exploration andproduction company focused on long-term growth through an aggressive exploration, development, production and acquisitionprogram in the Western Canadian Sedimentary Basin.

Tourmaline commenced active operations in the fall of 2008 with the objective of building a successful Canadian intermediate crudeoil and natural gas exploration, development and production company with a long-term business strategy similar to that of DuvernayOil Corp. and Berkley Petroleum Corp., companies previously founded and managed by certain key members of Tourmaline’s seniormanagement team. During the two-year period since commencing active operations, Tourmaline, through a series of strategicacquisitions, farm-ins and land acquisitions combined with its active capital exploration and development program, has assembled anextensive undeveloped land position with a large, multi-year drilling inventory and operating control of important natural gasprocessing and transportation infrastructure in two core long-term growth areas – the Alberta Deep Basin and the Greater PeaceRiver High. Tourmaline is executing a large-scale, repeatable capital exploration and development program in these two core long-term growth areas.

Tourmaline’s long-term business strategy is to increase shareholder value by building an extensive asset base over two to three coreexploration and production areas and exploiting and developing these areas to increase reserves, production and cash flows at anattractive return on invested capital. The Company seeks to execute this strategy by:

Š aggressively drilling and developing its extensive undeveloped land position;

Š adopting and employing advanced drilling and completion techniques;

Š enhancing returns by focusing on operational and cost efficiencies;

Š pursuing strategic acquisitions with significant potential synergies; and

Š wildcat exploration drilling for new pool discoveries.

Management believes Tourmaline has a number of competitive advantages that management expects will help the Companysuccessfully execute its long-term business strategy including:

Š an extensive undeveloped land position in two long-term growth areas;

Š a large, multi-year drilling inventory;

Š an incentivized management team with demonstrated operating and acquisition skills;

Š majority operating control of the Company’s core assets;

Š a strong balance sheet; and

Š a focus on operational efficiencies and cost containment.

(continued on next page)

(continued from cover)

This prospectus qualifies the distribution of 10,000,000 common shares (“Common Shares”) in the capital of Tourmaline at a price(the “Offering Price”) of $21.00 per Common Share (the “Offering”). The Offering Price of the Common Shares was determined bynegotiation between the Company and Peters & Co. Limited, FirstEnergy Capital Corp., Scotia Capital Inc., TD Securities Inc. andCormark Securities Inc. (collectively, the “Underwriters”).

There is no market through which the Common Shares may be sold and purchasers may not be able to resell Common Sharespurchased under this prospectus. This may affect the pricing of the Common Shares in the secondary market, the transparencyand availability of trading prices, the liquidity of the Common Shares and the extent of issuer regulation. See “Risk Factors”.The Toronto Stock Exchange (the “TSX”) has conditionally approved the listing of the Common Shares under the symbol “TOU”,subject to the Company fulfilling all the listing requirements of the TSX on or before February 8, 2011.

Price: $21.00 per Common Share

Price to thePublic

Underwriters’Commission(1)(3)

Net Proceeds to theCompany(2)(3)

Per Common Share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 21.00 $ 1.155 $ 19.845Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $210,000,000 $11,550,000 $198,450,000

Notes:(1) Pursuant to the terms of the Underwriting Agreement referred to under the heading “Plan of Distribution”, the Company has agreed to pay to the

Underwriters a commission equal to 5.5% of the gross proceeds of the Offering (the “Underwriters’ Commission”). See “Plan of Distribution”.(2) Before deducting expenses of the Offering, estimated to be $3,750,000, which, together with the Underwriters’ Commission, are payable by the

Company.(3) The Company has granted the Underwriters’ an option (the “Over-Allotment Option”) exercisable at the Underwriters’ discretion, to purchase from

the Company up to an additional 1,500,000 Common Shares (representing 15% of the number of Common Shares sold in the Offering) at a price equalto the Offering Price to cover over-allocations, if any. The Over-Allotment Option is exercisable in whole or in part, at any time on or before the datethat is 30 days following the closing of the Offering. If the Underwriters exercise the Over-Allotment Option in full, the total “Price to the Public”,“Underwriters’ Commission” and “Net Proceeds to the Company” will be $241,500,000, $13,282,500 and $228,217,500, respectively. This prospectusqualifies the grant of the Over-Allotment Option and the distribution of any Common Shares issued or sold pursuant to the exercise of the Over-Allotment Option. A purchaser who acquires Common Shares forming part of the Underwriters’ over-allocation position acquires such CommonShares under this prospectus, regardless of whether the over-allocation position is ultimately filled through the exercise of the Over-Allotment Optionor secondary market purchases. See “Plan of Distribution”.

Underwriters’ PositionMaximum Size or Number of

Securities Available Exercise Period Exercise Price

Over-Allotment Option Option to acquire up to1,500,000 Common Shares

Exercisable at any time upto 30 days following theclosing of the Offering

Equal to the Offering Price

In addition to, and apart from, the Offering, the Company’s President and Chief Executive Officer, Mr. Michael L. Rose, and ExecutiveVice President, Exploration, Mr. Robert N. Yurkovich (together, the “Private Placees”) have each entered into a subscriptionagreement with the Company pursuant to which the Private Placees will purchase, on a private placement basis, concurrent with theclosing of the Offering, an aggregate of 850,000 Common Shares (the “Private Placement Shares”) at the Offering Price for grossproceeds to the Company of $17,850,000 (the “Concurrent Private Placement”). No commission is payable to the Underwriters inconnection with the Concurrent Private Placement. See “Concurrent Private Placement” and “Directors and Executive Officers – ShareOwnership by Directors and Officers”.

The Underwriters, as principals, conditionally offer the Common Shares, subject to prior sale, if, as and when issued and sold by theCompany and delivered to and accepted by the Underwriters in accordance with the conditions contained in the UnderwritingAgreement referred to under “Plan of Distribution”, subject to approval of certain legal matters relating to the Offering on behalf of theCompany by Burnet, Duckworth & Palmer LLP and on behalf of the Underwriters by Blake, Cassels & Graydon LLP. In connectionwith the Offering, the Underwriters may effect transactions which stabilize or maintain the market price of the Common Shares at levelsother than those which otherwise might prevail on the open market. See “Plan of Distribution – Price Stabilization, Short Positions andPassive Market Making”.

Subscriptions for Common Shares will be received subject to rejection or allotment, in whole or in part. It is expected that certificatesrepresenting the Common Shares will be available for delivery at the Closing. Closing is expected to occur on or about November 23,2010 or such later date as the Company and the Underwriters may agree, but in any event not later than December 15, 2010 (the“Closing Date”). The Common Shares (other than any Common Shares issuable or to be sold on exercise of the Over-AllotmentOption) are to be taken up by the Underwriters, if at all, on or before a date not later than 42 days after the date of the receipt for thisprospectus. The Underwriters may offer the Common Shares at a lower price than stated above. See “Plan of Distribution –Pricing of the Offering”.

An investment in the Common Shares is speculative and involves a substantial degree of risk that should be considered bypotential purchasers. The Company’s business is subject to the risks normally encountered in the oil and gas industry. Aninvestment in the Common Shares is suitable only for those purchasers who are willing to risk a loss of some or all of theirinvestment and who can afford to lose some or all of their investment. See “Risk Factors”.

Scotia Capital Inc. and TD Securities Inc. are subsidiaries of Canadian chartered banks that are lenders to the Company.Consequently, the Company may be considered to be a “connected issuer” of such underwriters under applicable Canadiansecurities laws. See “Relationship Between the Company and Certain of the Underwriters”.

ii

NORTHWEST TERRITORIES

ALBERTA

NEBC

Edmonton

Calgary

Greater PeaceRiver High Core Area

AlbertaDeep BasinCore Area

Alta. Deep Basin

Alta./NEBCResource Plays



Western Canadian Sedimentary Basin - Selected Exploration and Production Areas

TourmalineLands

Sunrise/Dawson

AL

GreRiveAre

ADCEBC

rise/son

Adapted from Canadian Society ofPetroleum Geologists Publications

Central AlbertaDevonian Oil

Alberta Deep Basin Core Long-Term Growth Area

Cardium

Viking

Mannville

Bluesky

Gething

Falher

Gething

Cadomin

Dunvegan

R. 9 R. 7 R. 5 R. 3 R. 1, W6M

T. 57

T. 59

T. 61

T. 63

T. 65

R. 24 R. 22 R. 20 R. 18 R. 16

9

HintonHinton

Musreau/Musreau/KakwaKakwa

AnsellAnsell

EdsonEdsonMarshMarsh

HarleyHarley

Pine Ck.

WroeWroe

MineheadMinehead

HorseHorse

CeciliaCeciliaWild River

Sundance

Obed

Fir

T. 53

T. 55

T. 57

T. 59

T. 51

T. 49

Tourmaline Gas PlantTourmaline Gas Plant

Tourmaline 3D Tourmaline 3D

Tourmaline LandsTourmaline Lands

Possible Facility LocationsPossible Facility Locations

R. 24 R. 22 R. 20 R. 18 R. 16R. 26

6-32 Plant

Note:(1) All land and well information is provided on a gross company interest basis.

• Current Production 17,500 Boe/d• Tourmaline Land Base 1,550 sections• Drilling Inventory 3,100 locations

(2 wells per section only)• 2009 Gas wells drilled 29• 2010 Drilling Program 27 gas wells 2010/

20-25 additional wells• Existing Recompletion

Inventory 100

DevonianNon-Deposition

DunveganGas Field

on

Dawson Ck Montney

Pool

ParklandWabamunGas Pool Parkland

MontneyPool

Greater Peace River High Core Long-Term Growth Area

AlbertaNEBC

Tourmaline Gas Property

Tourmaline Oil Property

Tourmaline Gas Plant

Tourmaline Drilling Rig

T77

T81

T83

T79

T69

T73

T75

T71

T67

T85

R19R21 R 7R 9R11 R 1, W6MR 3R 5R23

T66

R15R17 R13

Note: (1) All land and well information is provided on a gross company interest basis.

• Current Production 4500 Boe/d

• 2010 Drilling 15 Montney horizontal Program gas wells and 2 Charlie Lake horizontal oil wells at Spirit River drilled to date

• Drilling Plans Additional 6-8 Montney horizontal wells planned in 2010

• Drilling Inventory In excess of 250 Montney horizontal locations

Sunrise/Dawson NEBC Montney/Doig Development (Greater Peace River High)

Doig 7-96.3 mmcf/d

Doig 3-32.6 mmcf/d

Doig 1-180.7 mmcf/d

Doig 14-340.5 mmcf/d

Doig 8-81.2 mmcf/d

5-18 Mntn Hz2.2 mmcf/d

15-12 MntnVert

Standing

Montney Vertical Wells.

LegendTourmaline Lands

Doig Producer

B-13-7Mntn Hz

2.8 mmcf/dA-13-7

Mntn Hz2.0 mmcf/d

TourmalineMetre Sta.

TourmalineComp. Sta.

TourmalinePlant Site

Tourmaline6”-8” HPG Pipeline

T. 80

T. 81

T. 79

R. 15R. 17R. 18 R. 16


A2-18 Mntn Hz7.7 mmcf/d choked

150 bbl/d

5-30 Mntn HzDrilling



2.2 bbl/d

2010 Montney Wells

Montney Proposed Loc.

8-23 Mntn HzStanding

Q4 2009 - to date 2010 Drilling Results 14 horizontals, average test rate 5.3 MMcf/d, 35 Bbls/mm condensate & liquids(8 wells tied in) (IP rates)

Second half 2010-11 Montney Program

Total Montney Drilling Inventory

Additional Doig opportunities

30-35 horizontals

150 horizontals

10 down-spacing locations

Note: (1) All land and well information is provided on a gross company interest basis.

ADVISORY

An investor should read this entire prospectus and consult the investor’s own professional advisors to assess theincome tax, legal, risk factors and other aspects of their investment in the Common Shares.

An investor should rely only on the information contained in this prospectus and is not entitled to rely on parts ofthe information contained in this prospectus to the exclusion of others. The Company has not, and the Underwritershave not, authorized anyone to provide investors with additional or different information. If anyone provides aninvestor with additional, different or inconsistent information, including statements in the media about theCompany, the investor should not rely on it.

The Company is not, and the Underwriters are not, offering to sell the Common Shares in any jurisdictions where theoffer or sale is not permitted. The information contained in this prospectus is accurate only as of the date of thisprospectus, regardless of the time of delivery of this prospectus or any sale of the Common Shares. The Company’sbusiness, financial condition, results of operations and prospects may have changed since the date of this prospectus.

For investors outside Canada, neither the Company nor any of the Underwriters have done anything that would permitthe Offering, or possession or distribution of this prospectus, in any jurisdiction where action for that purpose isrequired, other than in Canada. Investors are required to inform themselves about and to observe any restrictionsrelating to the Offering and the distribution of this prospectus.

INVESTORS ARE URGED TO READ THE INFORMATION UNDER THE HEADINGS “RISK FACTORS”,“CERTAIN RESERVES DATA INFORMATION”, “FORWARD-LOOKING STATEMENTS” AND “GAAPAND NON-GAAP FINANCIAL MEASURES”.

CONVENTIONS

The information in this prospectus assumes that the Over-Allotment Option is not exercised unless otherwise indicated.

Words importing the singular number include the plural and vice versa, and words importing any gender include allgenders.

All dollar amounts set forth in this prospectus are in Canadian dollars unless otherwise indicated.

All financial information in this prospectus has been presented in accordance with Canadian GAAP.

Certain terms used in this prospectus are defined under the headings “Glossary of Selected General Terms”, “Glossaryof Selected Oil and Gas Terms” and “Selected Abbreviations”. Certain other terms used in this prospectus but notdefined in this prospectus are defined in NI 51-101 and, unless the context otherwise requires, have the same meaningsherein as in NI 51-101.

TABLE OF CONTENTSPROSPECTUS SUMMARY . . . . . . . . . . . . . . . . . 1

TOURMALINE OIL CORP. . . . . . . . . . . . . . . . . . 18

DESCRIPTION OF THE BUSINESS . . . . . . . . . . . 18

DESCRIPTION OF CORE LONG-TERMGROWTH AREAS . . . . . . . . . . . . . . . . . . . . . . . 24

RECENT DEVELOPMENTS . . . . . . . . . . . . . . . . 26

STATEMENT OF RESERVES DATA ANDOTHER OIL AND GAS INFORMATION . . . . . 27

OTHER BUSINESS INFORMATION . . . . . . . . . . 43

SELECTED HISTORICAL AND PRO FORMACONSOLIDATED FINANCIAL ANDOPERATIONAL INFORMATION . . . . . . . . . . . 45

MANAGEMENT’S DISCUSSION ANDANALYSIS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

DIVIDENDS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69

DESCRIPTION OF SHARE CAPITAL . . . . . . . . . 69

CONSOLIDATED CAPITALIZATION . . . . . . . . . 71

OPTIONS TO PURCHASE COMMONSHARES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

PRIOR SALES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

ESCROWED COMMON SHARES . . . . . . . . . . . . 73

PRINCIPAL SHAREHOLDERS . . . . . . . . . . . . . . . 73

USE OF PROCEEDS . . . . . . . . . . . . . . . . . . . . . . . . 73

DIRECTORS AND EXECUTIVE OFFICERS . . . . 75

EXECUTIVE COMPENSATION . . . . . . . . . . . . . . 79

INDEBTEDNESS OF DIRECTORS ANDOFFICERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86

AUDIT COMMITTEE AND CORPORATEGOVERNANCE . . . . . . . . . . . . . . . . . . . . . . . . . 86

CERTAIN CANADIAN FEDERAL INCOMETAX CONSIDERATIONS . . . . . . . . . . . . . . . . . 87

ELIGIBILITY FOR INVESTMENT . . . . . . . . . . . . 89

PLAN OF DISTRIBUTION . . . . . . . . . . . . . . . . . 90

CONCURRENT PRIVATE PLACEMENT . . . . . 92

RELATIONSHIP BETWEEN THE COMPANYAND CERTAIN OF THEUNDERWRITERS . . . . . . . . . . . . . . . . . . . . . . 93

MARKET FOR SECURITIES . . . . . . . . . . . . . . . 93

INDUSTRY CONDITIONS . . . . . . . . . . . . . . . . . 93

RISK FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . 101

LEGAL PROCEEDINGS AND REGULATORYACTIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111

INTERESTS OF MANAGEMENT ANDOTHERS IN MATERIALTRANSACTIONS . . . . . . . . . . . . . . . . . . . . . . . 111

EXEMPTIONS FROM CERTAINDISCLOSURE REQUIREMENTS . . . . . . . . . 112

AUDITOR, TRANSFER AGENT ANDREGISTRAR . . . . . . . . . . . . . . . . . . . . . . . . . . . 112

MATERIAL CONTRACTS . . . . . . . . . . . . . . . . . 112

EXPERTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112

PURCHASERS’ STATUTORY RIGHTS OFWITHDRAWAL AND RESCISSION . . . . . . . 113

AUDITORS’ CONSENTS . . . . . . . . . . . . . . . . . . . 114

GLOSSARY OF SELECTED GENERALTERMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116

GLOSSARY OF SELECTED OIL AND GASTERMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 119

CERTAIN RESERVES DATAINFORMATION . . . . . . . . . . . . . . . . . . . . . . . . 122

SELECTED ABBREVIATIONS . . . . . . . . . . . . . . 123

SELECTED CONVERSIONS . . . . . . . . . . . . . . . . 123

EXCHANGE RATE DATA . . . . . . . . . . . . . . . . . 124

FORWARD-LOOKING STATEMENTS . . . . . . . 124

GAAP AND NON-GAAP FINANCIALMEASURES . . . . . . . . . . . . . . . . . . . . . . . . . . . 127

INDEX TO FINANCIAL STATEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FS-1INDEX TO MANAGEMENT’S DISCUSSION AND ANALYSIS FOR CERTAIN BUSINESS

ACQUISITIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . MDA-1

APPENDIX “A” MANDATE OF THE BOARD OF DIRECTORS AND CORPORATE GOVERNANCEDISCLOSURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

APPENDIX “B” AUDIT COMMITTEE MANDATE AND AUDIT COMMITTEE DISCLOSURE . . . . . . . B-1

APPENDIX “C” FORM 51-101F2 REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIEDRESERVES EVALUATORS – TOURMALINE RESERVES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-1

APPENDIX “D” FORM 51-101F3 REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GASDISCLOSURE – TOURMALINE RESERVES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . D-1

APPENDIX “E” FORM 51-101F2 REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIEDRESERVES EVALUATORS – EXSHAW RESERVES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . E-1

APPENDIX “F” FORM 51-101F3 REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GASDISCLOSURE – EXSHAW RESERVES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-1

CERTIFICATE OF THE COMPANY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . CC-1

CERTIFICATE OF THE UNDERWRITERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . CU-1

PROSPECTUS SUMMARY

The following is a summary of the principal features of the Offering and is qualified by and should be readtogether with the more detailed information, reserves and financial data and statements contained elsewhere in thisprospectus.

TOURMALINE OIL CORP.

Tourmaline was incorporated under the ABCA on July 21, 2008. Tourmaline is a Canadian intermediate crude oiland natural gas exploration and production company focused on long-term growth through an aggressive exploration,development, production and acquisition program in the WCSB. See “Tourmaline Oil Corp.”

DESCRIPTION OF THE BUSINESS

Overview

Tourmaline commenced active operations in the fall of 2008 with the objective of building a successful Canadianintermediate crude oil and natural gas exploration, development and production company with a long-term businessstrategy similar to that of Duvernay and Berkley, companies previously founded and managed by certain key membersof Tourmaline’s senior management team. During the two-year period since commencing active operations,Tourmaline, through a series of strategic acquisitions, farm-ins and land acquisitions combined with its active capitalexploration and development program, has assembled an extensive undeveloped land position with a large, multi-yeardrilling inventory and operating control of important natural gas processing and transportation infrastructure in twocore long-term growth areas – the Alberta Deep Basin and the Greater Peace River High.

Management believes that the location, size, concentration and other attributes of the Company’s two core long-term growth areas provide an opportunity for the Company to achieve operating cost, reserve recovery, deliverabilityand production efficiencies through a large-scale, repeatable capital exploration and development program. Tourmalineis aggressively executing this program using principally 3D seismic data to identify drilling locations for multi-stagefracture stimulations of vertical and horizontal wells.

As of the date of this prospectus, Tourmaline has:

Š approximately 1,356,000 gross (961,000 net) acres of land (approximately 80% of which is undeveloped);

Š in excess of 3,350 gross (2,400 net) drilling locations (based on two wells per section) and, in addition, up to1,000 gross potential horizontal drilling locations which are currently being assessed as part of the ongoingexploration and development drilling program;

Š in excess of 100 gross (65 net) recompletion locations; and

Š estimated current production of approximately 22,000 Boe/d and an estimated approximately 6,600 Boe/dbehind pipe awaiting tie-in.

1

2011 Capital Exploration and Development Program

Tourmaline’s 2011 capital exploration and development program has been budgeted at $425 million based on,among other things, prevailing commodity prices and industry conditions. The program is primarily focused on drilling inthe Alberta Deep Basin and Greater Peace River High areas, with $270.5 million (64%) expected to be directed todevelopment and exploration drilling and well completions, $100 million (23%) expected to be directed to the expansionand equipping of facilities and pipelines and $54.5 million (13%) expected to be directed to the acquisition of new landand seismic and geological data. Tourmaline estimates that in 2011 it will drill up to 87 gross (67 net) wells, of which 51gross (43 net) wells are expected to be in the Alberta Deep Basin, 24 gross (16 net) wells are expected to be in the GreaterPeace River High and 12 gross (8 net) are expected to be exploration wells.

A summary of Tourmaline’s 2011 capital exploration and development program is set forth below.

2011 Capital Exploration and Development Program Summary

Wells(Gross)

Wells(Net)

CapitalExpenditure

(MM$)

Development drilling and well completionsAlberta Deep Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51 43 180.5Greater Peace River High . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 16 66.0

75 59 246.5Exploration drilling and well completions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 8 24.0Expansion and equipping of facilities and pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 100.0Acquisition of new land and seismic and geological data . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 54.5

87 67 425.0

Business Strategy

Tourmaline’s long-term business strategy is to increase shareholder value by building an extensive asset base overtwo to three core exploration and production areas and exploiting and developing these areas to increase reserves,production and cash flows at an attractive return on invested capital. The Company seeks to execute this strategy by:

Š Aggressively Drilling and Developing Its Extensive Undeveloped Land Position. The Company intends toaggressively drill and develop its extensive undeveloped land position to maximize the value of its reserveand resource potential initially focusing on the drilling and development of its over 3,350 gross (2,400 net)drilling locations in the Alberta Deep Basin and the Greater Peace River High. Subject to industry conditions,ongoing drilling results and rig availability, Tourmaline initially plans to use eight operated drilling rigs toexecute its 2011 drilling program (with the potential of adding up to an additional four operated drilling rigslater in the year) and up to 12 operated drilling rigs to execute its 2012 drilling program. If drilling results aresuccessful, Tourmaline believes that additional rigs could be added to further expand these 2011 and 2012drilling programs. Assuming 12 operated drilling rigs are used by Tourmaline for a full year, Tourmalineanticipates that as many as 100 gross wells could be drilled in a year.

Š Adopting and Employing Advanced Drilling and Completion Techniques. Tourmaline’s management teamis focused on adopting and employing advanced drilling and completion techniques to maximize reserverecovery, deliverability, production and return on invested capital. These techniques have significantlyevolved over the last several years, resulting in increased initial production rates and recoverablehydrocarbons per well through the implementation of techniques such as using longer laterals and moretightly spaced multi-stage fracturing stimulation. Tourmaline continuously evaluates its drilling results andmonitors the results of other operators to improve operating practices and it expects its drilling andcompletion techniques will continue to evolve. Tourmaline believes that this continued evolution has thepotential to significantly enhance the Company’s ultimate reserve recovery, deliverability, production andrate of return on invested capital.

2

Š Enhancing Returns by Focusing on Operational and Cost Efficiencies. Tourmaline’s management team isfocused on continuous improvement in operating measures and has significant experience in successfullyexecuting large scale, repeatable capital exploration and development programs. Management believes that themagnitude and concentration of Tourmaline’s land position within its core long-term growth areas provides itwith the opportunity to capture economies of scale, including the ability to drill multiple wells from a singledrilling pad, utilize centralized production and fluid handling facilities and reduce the time and cost of rigmobilization.

Š Pursuing Strategic Acquisitions with Significant Potential Synergies. In the near-term, Tourmaline intends tocontinue to identify and seek to acquire additional land positions and producing assets in the Alberta DeepBasin and Greater Peace River High core areas to complement its existing operations. Over the long-term, theCompany expects to selectively target additional domestic basins that would allow it to employ its explorationand production strategy on large undeveloped land positions similar to those already accumulated.

Š Wildcat Exploration Drilling For New Pool Discoveries. Tourmaline intends to look for potentialopportunities to maximize long-term growth through wildcat exploration drilling for new pool discoveries,including in the Mississippian and Devonian formations. Tourmaline believes wildcat exploration drillingopportunities exist in the Alberta Deep Basin and Greater Peace River High core areas and, if suchopportunities are ultimately drilled and successful, they would provide the base for significant futuredevelopment projects and production growth. Management believes that Tourmaline has one of the fewexploration teams with deep Paleozoic experience and the Company has been acquiring prospective landsand delineating them with 3D seismic data since 2009. An extensive prospect inventory has been assembledand a wildcat drilling program is expected to commence in the second half of 2011. Tourmaline plans toallocate a modest portion of its budgeted capital exploration and development program each year towardswildcat exploration drilling.

Competitive Advantages

Management believes Tourmaline has a number of competitive advantages that management expects will help theCompany successfully execute its long-term business strategy:

Š Extensive Undeveloped Land Position in Two Long-Term Growth Areas. Tourmaline’s current landposition in the Alberta Deep Basin and the Greater Peace River High play areas is approximately 1,282,000gross (896,000 net) acres. This represents one of the largest concentrated leasehold positions in the lowerCretaceous formation in the Alberta Deep Basin and a significant leasehold position in the Montney play areain the Greater Peace River High. A majority of the Company’s land position is in areas where there iscurrently significant industry drilling activity. Moreover, certain lower Cretaceous formations in the AlbertaDeep Basin are amenable to horizontal drilling and Tourmaline’s 2010 and 2011 capital exploration anddevelopment programs includes evaluating this potential, which has not yet been included in the Company’s3,100 gross drilling locations for the Alberta Deep Basin.

Š Large, Multi-Year Drilling Inventory. Tourmaline has in excess of approximately 3,350 gross (2,400 net)drilling locations, of which 3,100 are Alberta Deep Basin Cretaceous vertical wells (at two wells per section)and 250 are Montney horizontal wells in the Greater Peace River High. The Company plans to drill up to 87gross (67 net) wells in its long-term growth areas in 2011, which represents less than 3% of the Company’sgross drilling locations in these two areas.

Š Management Team with Demonstrated Operating and Acquisition Skills. Tourmaline’s senior managementteam has extensive expertise in the oil and natural gas industry as former senior management of Duvernay,Berkley and other Canadian exploration and production companies. The senior technical team has an averageof more than 25 years of oil and natural gas industry experience, including experience in multiple WCSBconventional and resource plays, as well as experience in other North American basins. The Companybelieves its management and technical team is one of the Company’s principal competitive strengths relativeto its industry peers due to the team’s track record in the identification, acquisition and execution ofexploration and production programs and opportunities. In addition, key members of the team possesssubstantial expertise in horizontal drilling, completion techniques and acquiring and managing largeexploration and development programs.

3

Š Incentivized Management Team. Tourmaline’s management team currently owns approximately 26% of theoutstanding Common Shares (approximately 25% immediately following the completion of the Offering andthe Concurrent Private Placement). In addition, the management team has Options to acquire an additional3,550,000 Common Shares. This ownership interest provides a significant incentive for the Company’smanagement to continue to grow the value of the Company’s business for the benefit of all shareholders.

Š Majority Operating Control of the Company’s Core Assets. In order to maintain better control over theCompany’s asset portfolio, Tourmaline has established a significant land position comprised primarily ofproperties that it operates. The Company currently operates approximately 80% of its 3,350 gross drillinglocations, or approximately 90% of its 2,400 net drilling locations. As of December 31, 2009, approximately81% of total proved reserves of Tourmaline and Exshaw (without reduction to reflect the 9.4% third-partyminority interest in Exshaw) were attributable to properties it operates. Approximately 90% of theCompany’s budgeted 2011 capital exploration and development program is related to operated wells, whichTourmaline anticipates will result in an increase in the percentage of its proved reserves attributable toproperties it operates. As of December 31, 2009, the Company’s average working interest in its operated andnon-operated drilling locations was 80% and 50%, respectively. Tourmaline believes controlling operationswill allow it to dictate the pace of development as well as better manage the cost, type and timing ofexploration and development activities. The Company believes that maintaining operational control over themajority of its land position will allow it to better pursue its strategies of enhancing returns throughoperational and cost efficiencies and maximizing hydrocarbon recovery through improvement of drilling andcompletion techniques. The Company also operates substantial natural gas gathering and processing facilitiesin the Alberta Deep Basin, controlling 200 MMcf/d of capacity, and similarly operates field processingfacilities in the Greater Peace River High with 30 MMcf/d of capacity.

Š Strong Balance Sheet. Tourmaline has and plans to maintain, through the application of budget controls andprudent financial management, a strong balance sheet with manageable debt levels relative to its marketcapitalization and prospective cash flows to provide it with the financial flexibility to successfully execute itsaggressive growth strategy. No amounts will be drawn under the Credit Facilities on completion of theOffering and the Concurrent Private Placement. See “Use of Proceeds” and “Consolidated Capitalization”.

Š Focus on Operational Efficiencies and Cost Containment. Management believes that Tourmaline hasefficient operational cost containment as illustrated by its strong operating cost results of $7.94/Boe in thefourth quarter of 2009, $7.22/Boe in the first quarter of 2010, $6.98/Boe in the second quarter of 2010, and$6.24/Boe in the third quarter of 2010. By directing larger percentages of natural gas into operated facilities,continuing to bring on-stream productive new natural gas wells and optimizing existing facilities,management estimates that Alberta Deep Basin operating expenses will continue to be reduced over the next12 months. Similarly, G&A expenses per Boe, excluding interest, finance charges, stock-based compensationand capitalized G&A, have been trending downward as follows: fourth quarter of 2009, $1.74/Boe; firstquarter of 2010, $1.44/Boe; second quarter of 2010, $1.04/Boe; and third quarter of 2010, $0.95/Boe.

Three-Year History

In a little less than two years, Tourmaline has grown into an intermediate crude oil and natural gas exploration andproduction company with current production estimated at approximately 22,000 Boe/d and an estimated 6,600 Boe/dbehind pipe awaiting tie-in. During this period, the Company has raised close to $1.0 billion through private placementequity financings, approximately $280.7 million of which was raised from Tourmaline’s directors, officers and theirassociates, and strategically completed 17 acquisitions to cost-effectively build its current production and extensiveland position. The acquisitions have been complemented by an aggressive exploration, development and productionprogram that is intended to be the Company’s primary long-term growth engine.

4

The following table summarizes the Company’s significant acquisitions.

Significant Acquisition Summary

Date Acquisition Areas

PurchasePrice

(MM$)(1)Production(2)

(Boe/d)

Undeveloped Land

GrossAcres

NetAcres

April 30, 2009 Alberta Deep Basin Acquisition Hinton / Musreau / Narraway $103.0 2,350 86,072 27,466August 28, 2009 Wild River Acquisition Wild River, Harley, Olsen

and Sundance $145.9 2,550 44,196 24,016September 15, 2009 Pienza Acquisition(3) Sunrise NEBC $ 50.0 350 23,348 15,980November 10, 2009 Exshaw Acquisition Peace River Arch $131.8 2,510 56,960 41,718November 10, 2009 Vigilant Acquisition(3) Musreau / Chime /

Whitecourt $ 47.5 650 92,734 88,538January 14, 2010 Altia Acquisition Dawson NEBC $100.8 1,500 122,600 56,980June 1, 2010 Greater Hinton Acquisition Greater Hinton $275.0 4,000 266,849 204,560

$854.0 13,910 692,759 459,258

Notes:(1) These amounts reflect the purchase price paid in cash and/or Common Shares and associated transaction costs.(2) Estimated production as at the effective date of the acquisition.(3) Subsequent to the Pienza Acquisition and Vigilant Acquisition, Tourmaline amalgamated with Pienza and Vigilant on January 1, 2010 under the

ABCA, continuing as Tourmaline Oil Corp.

The following table summarizes the equity financings completed by the Company since commencement of activeoperations as well as the Company insider, employee and associate participation in such equity financings.

Summary of Equity Financings

Financings Insider, Employee and Associate Participation(7)

DateSharesIssued

Total GrossProceeds Gross Subscriptions

Percentage ofGross Proceeds

October 27, 2008 . . . . . . . . . . . . . . . . . . . . . . . 50,500,000(1) $301,000,000 $147,000,000 48.8%December 17, 2008 . . . . . . . . . . . . . . . . . . . . . . 2,500,000(2) $ 25,000,000 $ 12,500,000 50.0%May 28, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . 14,000,000(3) $140,000,000 $ 30,000,000 21.4%November 10, 2009 . . . . . . . . . . . . . . . . . . . . . . 13,543,624(4) $208,404,360 $ 47,904,360 23.0%March 19, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . 11,950,000(5) $223,920,000 $ 36,720,000 16.4%August 12, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . 1,150,000(6) $ 25,300,000 $ 6,600,000 26.1%

93,643,624 $923,624,360 $280,724,360 30.4%

Notes:(1) Private placement of 15,000,000 Common Shares at $3.50 per share and 35,500,000 Common Shares at $7.00 per share.(2) Private placement of 2,500,000 Flow-Through Shares at $10.00 per share.(3) Private placement of 14,000,000 Common Shares at $10.00 per share.(4) Private placement of 11,793,624 Common Shares at $15.00 per share and 1,750,000 Flow-Through Shares at $18.00 per share.(5) Private placement of 9,500,000 Common Shares at $18.00 per share and 2,450,000 Flow-Through Shares at $21.60 per share.(6) Private placement of 1,150,000 Flow-Through Shares at $22.00 per share.(7) Represents percentage of insider, employee and associate participation for the total amount raised by the Company, which has been calculated

based on the percentage of Common Shares issued to directors, officers, employees and other service providers of the Company and certainfamily, friends and business associates of the foregoing relative to the total number of Common Shares issued in each financing.

See “Description of the Business”, “Description of Core Long-Term Growth Areas”, “Recent Developments”,“Other Business Information”, “Industry Conditions” and “Risk Factors”.

5

SUMMARY OF RESERVES DATA

The reserves data set forth below is based upon the Reserve Reports. The Reserve Reports evaluate the crude oil,NGL and natural gas reserves of Tourmaline (evaluated by GLJ in the GLJ Tourmaline Reserve Report) and Exshaw(evaluated by AJM in the AJM Exshaw Reserve Report, without reduction to reflect the 9.4% third-party minorityinterest in Exshaw) and the net present values of future net revenue for these reserves using forecast prices and costs.The Reserve Reports have been prepared in accordance with the standards contained in the COGE Handbook and thereserve definitions contained in NI 51-101 and the COGE Handbook. Additional information not required byNI 51-101 has been presented to provide continuity and additional information which Tourmaline believes is importantto the readers of this information prospectus. GLJ and AJM were engaged to provide evaluations of proved and provedplus probable reserves and no attempt was made to evaluate possible reserves.

All of Tourmaline’s and Exshaw’s reserves are in Canada and, more specifically in the provinces of Alberta andBritish Columbia.

There are numerous uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and thefuture cash flows attributed to such reserves. The reserve and associated cash flow information set forth in thisprospectus are estimates only. In general, estimates of economically recoverable oil and natural gas reserves and thefuture net cash flows therefrom are based upon a number of variable factors and assumptions, such as historicalproduction from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures,marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies andfuture operating costs, all of which may vary materially from actual results. For those reasons, estimates of theeconomically recoverable oil and natural gas reserves attributable to any particular group of properties, classification ofsuch reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared bydifferent engineers, or by the same engineers at different times, may vary. The Company’s actual production, revenues,taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof andsuch variations could be material.

The information relating to the crude oil and natural gas reserves of Tourmaline and Exshaw contains forward-looking statements relating to future net revenues, forecast capital expenditures, future development plans and costsrelated thereto, forecast operating costs, anticipated production and abandonment costs. See “Statement of ReservesData and Other Oil and Gas Information”, “Forward-Looking Statements”, “Certain Reserves Data Information”,“Industry Conditions” and “Risk Factors – Reserves Estimates”.

6

Tourmaline and Exshaw Combined Reserves

The reserves data for the Tourmaline and Exshaw combined reserves set forth below has been derived fromthe Reserve Reports and reflects 100% of Exshaw’s reserves without reduction to reflect the 9.4% third-partyminority interest in Exshaw.

The reserves data for the Tourmaline and Exshaw combined reserves set forth below has been prepared by GLJ andis based on the data contained in the Reserve Reports adjusted to apply certain of GLJ’s assumptions and methodologiesused in the preparation of the GLJ Tourmaline Reserve Report to the AJM Exshaw Reserve Report. Accordingly, thecombined reserves information for Tourmaline and Exshaw below varies from the reserve information that would bederived from a simple arithmetic summation of the GLJ Tourmaline Reserve Report and the AJM Exshaw ReserveReport.

Summary of Crude Oil and Natural Gas Reserves andNet Present Values of Future Net Revenue

as of December 31, 2009Forecast Prices and Costs

Light and Medium Crude Oil Natural Gas NGL

Reserves Category

CompanyGross

(Mbbls)

CompanyNet

(Mbbls)

CompanyGross

(MMcf)

CompanyNet

(MMcf)

CompanyGross

(Mbbls)

CompanyNet

(Mbbls)

Proved Developed Producing . . . . . . . . . . . . . . . 1,070 877 90,834 81,106 1,006 642Proved Developed Non-Producing . . . . . . . . . . . 82 63 20,479 18,609 254 183Proved Undeveloped . . . . . . . . . . . . . . . . . . . . . . 716 552 74,099 63,689 847 583

Total Proved Reserves . . . . . . . . . . . . . . . . . . . . . 1,869 1,492 185,412 163,403 2,107 1,409Total Probable Reserves . . . . . . . . . . . . . . . . . . . 2,871 2,192 121,704 101,520 1,355 896

Total Proved Plus Probable Reserves . . . . . . . 4,740 3,684 307,116 264,923 3,462 2,305

Net Present Values Of Future Net Revenue ($000s)

Before Future Income Taxes Discounted at(%/year)

After Future Income Taxes Discounted at(%/year)

Unit ValueBefore IncomeTax Discountedat 10%/year

Reserves Category 0 5 10 15 20 0 5 10 15 20 ($/Mcfe) ($/Boe)

Proved Developed Producing . . . . 527,563 411,283 339,326 290,734 255,765 527,563 411,283 339,326 290,734 255,765 3.76 22.57Proved Developed

Non-Producing . . . . . . . . . . . . . 123,557 95,613 77,963 65,958 57,314 103,823 81,671 67,663 58,064 51,079 3.88 23.29Proved Undeveloped . . . . . . . . . . . 252,121 152,430 93,534 56,199 31,178 188,992 108,136 60,309 29,998 9,733 1.33 7.96

Total Proved Reserves . . . . . . . . . . 903,241 659,326 510,824 412,892 344,258 820,378 601,090 467,297 378,796 316,577 2.83 16.95Total Probable Reserves . . . . . . . . 744,297 441,162 290,608 204,779 150,911 562,722 326,904 210,550 144,462 103,140 2.42 14.52

Total Proved Plus ProbableReserves . . . . . . . . . . . . . . . . . . 1,647,538 1,100,488 801,432 617,670 495,169 1,383,100 927,994 677,848 523,258 419,717 2.66 15.98

7

Tourmaline Stand Alone Reserves

The reserve data for Tourmaline set forth below has been derived from the GLJ Tourmaline Reserve Report anddoes not include Exshaw’s reserves evaluated in the AJM Exshaw Reserve Report.

Summary of Crude Oil and Natural Gas Reservesand Net Present Values of Future Net Revenue



Reserves Category

CompanyGross

(Mbbls)

Company Netof Royalty(Mbbls)

CompanyGross

(MMcf)

Company Netof Royalty(MMcf)

CompanyGross

(Mbbls)


Proved Developed Producing . . . . . . . . . 305 228 77,560 71,365 894 579Proved Developed Non-Producing . . . . . 0 0 18,704 17,270 239 175Proved Undeveloped . . . . . . . . . . . . . . . . 50 42 62,353 55,055 747 522

Total Proved Reserves . . . . . . . . . . . . . . . 355 270 158,617 143,690 1,880 1,276Total Probable Reserves . . . . . . . . . . . . . 157 121 96,432 83,854 1,147 774

Total Proved Plus ProbableReserves . . . . . . . . . . . . . . . . . . . . . . . . 512 391 255,048 227,545 3,027 2,050


Before Future Income Taxes Discounted At(%/year)





Non-Producing . . . . . . . . . . . . . . 113,410 87,243 70,910 59,912 52,056 113,410 87,243 70,910 59,912 52,056 3.87 23.23Proved Undeveloped . . . . . . . . . . . 205,012 117,641 66,878 35,252 14,427 158,536 88,925 48,001 22,181 4,974 1.14 6.87


Total Proved Plus ProbableReserves . . . . . . . . . . . . . . . . . . 1,265,106 817,832 581,057 439,144 346,310 1,097,406 718,738 516,080 393,200 311,977 2.40 14.40

8

Exshaw Stand Alone Reserves

The reserves data for Exshaw set forth below has been derived from the AJM Exshaw Reserve Report. TheExshaw reserves data reflects 100% of Exshaw’s reserves and has not been reduced to reflect the 9.4% third-party minority interest in Exshaw.




Reserves Category

CompanyGross

(Mbbls)


CompanyGross

(MMcf)


CompanyGross

(Mbbls)


Proved Developed Producing . . . . . . . . . . . . . . . . . . 764.8 638.7 13,159.2 9,444.9 111.2 62.5Proved Developed Non-Producing . . . . . . . . . . . . . . 82.3 55.7 1,728.2 1,292.3 14.8 8.5Proved Undeveloped . . . . . . . . . . . . . . . . . . . . . . . . . 666.2 508.2 11,745.0 9,080.6 99.7 61.6

Total Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . 1,513.2 1,202.6 26,632.4 19,817.8 225.7 132.5Total Probable Reserves . . . . . . . . . . . . . . . . . . . . . . 2,713.6 1,997.5 25,270.6 17,534.8 208.4 122.1

Total Proved Plus Probable Reserves . . . . . . . . . . 4,226.8 3,200.1 51,903.0 37,352.6 434.1 254.6

Net Present Values of Future Net Revenue ($000s)

Before Future Income Taxes DiscountedAt

(%/year)After Future Income Taxes Discounted at

(%/year)

UnitValueBeforeIncomeTax

Discountedat 10%/year


Proved Developed Producing . . . . . . . . . . . 85,488 74,157 65,701 59,185 54,022 85,488 74,157 65,702 59,185 54,022 4.81 28.88Proved Developed Non-Producing . . . . . . . 9,482 7,779 6,521 5,564 4,817 9,482 7,779 6,521 5,564 4,817 3.89 23.32Proved Undeveloped . . . . . . . . . . . . . . . . . . 49,207 35,694 26,850 20,688 16,190 40,238 27,834 19,902 14,502 10,645 2.15 12.89

Total Proved Reserves . . . . . . . . . . . . . . . . 144,177 117,630 99,073 85,436 75,029 135,208 109,770 92,126 79,250 69,483 3.56 21.36Total Probable Reserves . . . . . . . . . . . . . . . 255,536 173,315 124,990 94,168 73,330 194,897 130,464 93,054 69,414 53,555 4.13 24.79

Total Proved Plus Probable Reserves . . . 399,713 290,946 224,062 179,605 148,359 330,105 240,233 185,180 148,664 123,038 3.86 23.15

9

2010 Acquired Reserves

The following tables disclose the estimated reserves and related future net revenue attributable to reservesacquired by Tourmaline in 2010 pursuant to the Altia Acquisition and the Greater Hinton Acquisition, as well as thepricing assumptions used to develop these estimates and the estimated crude oil, NGL and natural gas productionvolumes for each acquisition for the first year reflected in these estimates. The estimates of future net revenuedisclosed do not represent fair market value. The estimates of crude oil, natural gas and NGL reserves provided hereinare estimates only. Actual crude oil, natural gas and NGL reserves may be greater or less than the estimates providedherein.

Altia Reserves as at March 31, 2009

The reserves data set forth below is based upon the Sproule Altia Reserve Report. The Sproule Altia ReserveReport evaluates the crude oil, NGL and natural gas reserves of Altia which were acquired by Tourmaline pursuant tothe Altia Acquisition and the net present values of future net revenue for these reserves using forecast prices and costs.The Sproule Altia Reserve Report has been prepared in accordance with the standards contained in the COGEHandbook and the reserve definitions contained in NI 51-101 and the COGE Handbook.

The information relating to the crude oil, NGL and natural gas reserves of Altia contains forward-lookingstatements relating to future net revenues and anticipated production. See “Forward-Looking Statements”, “CertainReserves Data Information”, “Industry Conditions” and “Risk Factors – Reserves Estimates”.

Summary of Crude Oil and Natural Gas ReservesBased on Forecast Prices and Costs


Reserves Category

CompanyGross

(Mbbls)

CompanyNet ofRoyalty(Mbbls)

CompanyGross

(MMcf)

CompanyNet ofRoyalty(MMcf)

CompanyGross

(Mbbls)


Proved Developed Producing . . . . . . . . . . . . . . . 4.8 4.6 5,624 4,256 7.9 5.0Proved Developed Non-Producing . . . . . . . . . . . — — 628 466 29.6 23.7Proved Undeveloped . . . . . . . . . . . . . . . . . . . . . . 10.9 10.6 4,809 3,556 223.5 178.8

Total Proved Reserves . . . . . . . . . . . . . . . . . . . . . 15.8 15.2 11,061 8,277 261.0 207.4Total Probable Reserves . . . . . . . . . . . . . . . . . . . 12.5 11.6 5,510 4,194 123.7 98.2

Total Proved Plus Probable Reserves . . . . . . . 28.3 26.7 16,571 12,471 384.6 305.7

Summary of Present Values of Future Net RevenueBased on Forecast Prices And Costs

Before Income Taxes Discounted at (%/Year)

Unit Value beforeIncome TaxDiscounted at

Reserves Category0

(M$)5

(M$)10

(M$)15

(M$)20

(M$)10%/yr($/Boe)

Proved Developed Producing . . . . . . . . . . . . . . . . . . . . 19,653 18,006 16,668 15,558 14,623 23.19Proved Developed Non-Producing . . . . . . . . . . . . . . . . 2,895 2,440 2,083 1,798 1,566 20.56Proved Undeveloped . . . . . . . . . . . . . . . . . . . . . . . . . . . 19,663 12,228 7,801 4,955 3,021 9.98

Total Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . 42,211 32,674 26,552 22,311 19,210 16.57Total Probable Reserves . . . . . . . . . . . . . . . . . . . . . . . . 31,245 18,520 13,057 10,044 8,112 16.14

Total Proved Plus Probable Reserves . . . . . . . . . . . . 73,456 51,194 39,608 32,355 27,322 16.43

10

Greater Hinton Reserves as at November 30, 2009

The reserves data set forth below is based upon the AJM Greater Hinton Reserve Report. The AJM GreaterHinton Reserve Report evaluates the crude oil, NGL and natural gas reserves of the assets acquired by Tourmalinepursuant to the Greater Hinton Acquisition and the net present values of future net revenue for these reserves usingforecast prices and costs. The AJM Greater Hinton Reserve Report has been prepared in accordance with the standardscontained in the COGE Handbook and the reserve definitions contained in NI 51-101 and the COGE Handbook.

The information relating to the crude oil, NGL and natural gas reserves of the assets acquired by Tourmalinepursuant to the Greater Hinton Acquisition contains forward-looking statements relating to future net revenues andanticipated production. See “Forward-Looking Statements”, “Certain Reserves Data Information”, “IndustryConditions” and “Risk Factors – Reserves Estimates”.


Reserves Category

Medium Crude Oil Natural Gas NGL

CompanyGross

(Mbbls)


CompanyGross

(MMcf)


CompanyGross

(Mbbls)


Proved Developed Producing . . . . . . . . . . . . . . . . . . . . 18 14 55,797 47,193 32 22Proved Developed Non-Producing . . . . . . . . . . . . . . . . — — 3,229 2,881 11 8Proved Undeveloped . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 57,251 49,276 67 50

Total Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . 18 14 116,278 99,350 110 81Total Probable Reserves . . . . . . . . . . . . . . . . . . . . . . . . 7 5 86,470 69,842 82 56

Total Proved Plus Probable Reserves . . . . . . . . . . . . 25 19 202,748 169,192 192 137




Reserves Category0

(M$)5

(M$)10

(M$)15

(M$)20

(M$)10%/yr($/Boe)

Proved Developed Producing . . . . . . . . . . . . . . 310,084 208,416 158,216 129,043 110,108 20.02Proved Developed Non-Producing . . . . . . . . . . 16,043 10,840 8,189 6,596 5,531 16.78Proved Undeveloped . . . . . . . . . . . . . . . . . . . . 230,000 115,641 61,283 30,900 11,893 7.42

Total Proved Reserves . . . . . . . . . . . . . . . . . . . 556,128 334,898 227,688 166,539 127,532 13.67Total Probable Reserves . . . . . . . . . . . . . . . . . . 549,673 192,093 83,979 40,050 18,283 7.18

Total Proved Plus Probable Reserves . . . . . . 1,105,801 526,991 311,667 206,589 145,815 10.99

See “Statement of Reserves Data and Other Oil and Gas Information”.

11

SELECTED HISTORICAL AND PRO FORMACONSOLIDATED FINANCIAL AND OPERATIONAL INFORMATION

Selected Historical Consolidated Financial and Operational InformationThe following table sets out selected consolidated historical financial and operational information as at and for the

periods indicated.

The selected historical consolidated financial information set out below as at December 31, 2009 and 2008, andfor the year ended December 31, 2009 and the period from incorporation on July 21, 2008 to December 31, 2008, hasbeen derived from the Company’s audited consolidated financial statements and related notes appearing elsewhere inthis prospectus. The Company’s audited consolidated financial statements appearing elsewhere in this prospectus havebeen audited by the Company’s auditors, KPMG LLP. KPMG LLP’s auditor’s report on these consolidated financialstatements is included elsewhere in this prospectus. The selected historical consolidated financial information set outbelow as at September 30, 2010 and 2009 and for the nine months ended September 30, 2010 and 2009 has beenderived from the Company’s unaudited interim consolidated financial statements included elsewhere in this prospectus.The unaudited consolidated financial information presented has been prepared on a basis consistent with theCompany’s audited consolidated financial statements. Investors should read the selected historical consolidatedfinancial information in conjunction with “Management’s Discussion and Analysis” and the Company’s audited andunaudited consolidated financial statements and the accompanying notes, which financial statements are includedelsewhere in this prospectus.

As at and for the nine months endedAs at and forthe year ended

December 31, 2009

As at and for the periodfrom incorporation on

July 21, 2008 toDecember 31, 2008September 30, 2010 September 30, 2009

ProductionNatural gas (Mcf) . . . . . . . 23,644,856 3,396,003 6,850,937 —Crude oil and NGL

(Bbls) . . . . . . . . . . . . . . . 464,852 28,369 119,347 —Oil equivalent (Boe) . . . . . 4,405,661 594,370 1,261,170 —Natural gas (Mcf/d) . . . . . . 86,611 12,440 18,770 —Crude oil and NGL

(Bbls/d) . . . . . . . . . . . . . 1,703 104 327 —Oil equivalent (Boe/d) . . . . 16,138 2,177 3,455 —

Financial ($000s, unlessotherwise noted)Revenue, net of

royalties . . . . . . . . . . . . . 153,615 12,644 35,127 1,237Cash flow from

operations . . . . . . . . . . . 97,999 8,874 (514) 522Funds from

operations(1) . . . . . . . . . . 89,651 7,154 21,722 802Per diluted share . . . . . . . . 0.74 0.13 0.31 0.04Net earnings (loss) . . . . . . 17,145 (1,752) (2,121) 438Per basic share . . . . . . . . . . 0.15 (0.03) (0.03) 0.02Per diluted share . . . . . . . . 0.14 (0.03) (0.03) 0.02Total assets . . . . . . . . . . . . 1,540,236 561,339 1,003,882 321,779Working capital . . . . . . . . . (65,154) 84,622 161,514 314,743Working capital (adjusted

for the fair value offinancial instrumentsand future taxes)(1) . . . . . (78,314) 84,622 161,190 314,743

Long-term financialliabilities . . . . . . . . . . . . 56,706 — — —

Capital Expenditures . . . . . 598,082 373,312 499,258 3,575Basic outstanding shares

(000s) . . . . . . . . . . . . . . 123,841 73,553 101,809 53,000

Per UnitNatural gas ($/Mcf) . . . . . . 4.69 3.38 4.24 —Crude oil and NGL

($/Bbl) . . . . . . . . . . . . . . 73.57 59.95 66.10 —Revenue ($/Boe) . . . . . . . . 32.95 22.20 29.28 —Operating and

transportation costs($/Boe) . . . . . . . . . . . . . 8.46 5.97 7.91 —

Operating netback(1)

($/Boe) . . . . . . . . . . . . . 21.31 11.82 17.58 —

Notes:(1) See “GAAP and Non-GAAP Financial Measures” and “Management’s Discussion and Analysis – Non-GAAP Financial Measures”.(2) Certain amounts have been restated for purchase price adjustments relating to property acquisitions that occurred in prior periods.

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Selected Pro Forma Consolidated Financial and Operational Information

The following table sets out selected unaudited pro forma consolidated financial and operational information as atand for the periods indicated after giving effect to the Tourmaline Significant Acquisitions, the completion of theOffering and the Concurrent Private Placement.

The selected unaudited pro forma consolidated financial information set out below has been derived from theCompany’s unaudited pro forma consolidated financial statements and accompanying notes included elsewhere in thisprospectus. Investors should read the selected pro forma consolidated financial information in conjunction with theCompany’s unaudited pro forma consolidated financial statements and the consolidated financial statements andaccompanying notes of the Company from which the unaudited pro forma consolidated financial statements arederived, which financial statements are included elsewhere in this prospectus. The Company’s unaudited pro formaconsolidated financial statements have been prepared by management of Tourmaline in accordance with CanadianGAAP. In the opinion of management, the unaudited pro forma consolidated financial statements include alladjustments necessary for fair presentation in accordance with Canadian GAAP. The unaudited pro forma consolidatedfinancial statements are not necessarily indicative of either the financial position or results of operations that actuallywould have occurred if the events reflected therein had been in effect on the dates indicated or of the results that maybe obtained in the future. The unaudited pro forma consolidated financial statements do not contemplate future changesin accounting policies due to the adoption of IFRS.

Unaudited pro forma as atand for the nine months

ended September 30, 2010

Unaudited pro formafor the

year ended December 31, 2009

ProductionNatural gas (Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27,696,960 27,781,676Crude oil and NGL (Bbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 477,071 510,359Oil equivalent (Boe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,093,231 5,140,639Gas (Mcf/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101,454 76,114Crude oil and NGL (Bbls/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,748 1,398Oil equivalent (Boe/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18,657 14,084

Financial ($000s, unless otherwise noted)Revenue, net of royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 169,755 125,773Funds from operations(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104,062 77,137Per diluted share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.78 0.73Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17,349 (13,132)Per basic share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.13 (0.13)Per diluted share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.13 (0.13)Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,711,600 (3)

Working capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106,210 (3)

Working capital (adjusted for the fair value of financialinstruments and future taxes)(1) . . . . . . . . . . . . . . . . . . . . . . . 93,050 (3)

Basic outstanding shares (000s) . . . . . . . . . . . . . . . . . . . . . . . . . 134,691 121,571

Per Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Natural gas ($/Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.66 4.16Crude oil and NGL ($/Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73.56 54.73Revenue ($/Boe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32.23 27.93Operating and transportation costs ($/Boe) . . . . . . . . . . . . . . . . 7.67 7.28Operating netback(1) ($/Boe) . . . . . . . . . . . . . . . . . . . . . . . . . . . 21.26 16.57

Notes:(1) See “GAAP and Non-GAAP Financial Measures” and “Management’s Discussion and Analysis – Non-GAAP Financial Measures”.(2) Certain amounts have been restated for purchase price adjustments relating to property acquisitions that occurred in prior periods.(3) A pro forma balance sheet as at December 31, 2009 has not been prepared.(4) The underlying assumptions for the pro forma adjustments provide a reasonable basis for presenting the significant financial effects directly

attributable to the transactions discussed herein, however, the pro forma consolidated financial statements are not necessarily indicative of theresults of operations expected in future years.

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Selected Combined Reserves and Land Holding Information

The follow table sets out selected combined reserves and land holding information after giving effect to the AltiaAcquisition and the Greater Hinton Acquisition.

Important information concerning the oil and natural gas reserves of the Company is contained under the heading“Statement of Reserves Data and Other Oil and Gas Information”. Readers are encouraged to carefully review thatsection of the prospectus as the information set forth in the table below is a summary only and is qualified in itsentirety by the more detailed information contained in that section.

TourmalineAltia

AcquisitionGreater Hinton

Acquisition Combined

Reserves(1)Total Proved reserves(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Light and Medium Crude Oil (Mbbls) . . . . . . . . . . . . . . . . . . . . . 1,869 15.8 18.0 1,902.8Natural Gas (MMcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 185,412 11,061.0 116,278.0 312,751.0NGL (Mbbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,107 261.0 110.0 2,478.0Total Oil Equivalent (Mboe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34,878 2,120.3 19,507.7 56,506.0

Total Proved Plus Probable Reserves(1) . . . . . . . . . . . . . . . . . . . . . .Light and Medium Crude Oil (Mbbls) . . . . . . . . . . . . . . . . . . . . . 4,740 28.3 25.0 4,793.3Natural Gas (MMcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 307,116 16,571.0 202,748.0 526,435.0NGL (Mbbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,462 384.6 192.0 4,038.6Total Oil Equivalent (Mboe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59,388 3,174.7 34,008.3 96,571.0

Developed and Undeveloped land holdings(2)Gross Acres . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 907,000 153,000 296,000 1,356,000Net Acres . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 674,000 66,000 221,000 961,000

Notes:(1) As at December 31, 2009, in respect of Tourmaline based upon the Reserve Reports (and includes Exshaw without reduction to reflect the 9.4%

third-party minority interest in Exshaw), as at March 31, 2009 in respect of Altia based on the Sproule Altia Reserve Report and as atNovember 30, 2009 in respect of the assets acquired pursuant to the Greater Hinton Acquisition based on the AJM Greater Hinton ReserveReport. The combined volume is an arithmetic sum of multiple estimates of proved or proved plus probable reserves, respectively, as containedin these reports, which have been prepared by different engineers as of different dates. See “Risk Factors – Reserve Estimates.”

(2) As at November 8, 2010.

See “Selected Historical and Pro Forma Consolidated Financial and Operational Information”.

14

THE OFFERING

Issuer: Tourmaline Oil Corp.

Offering: 10,000,000 Common Shares. See “Description of Share Capital” for more informationregarding the Common Shares.

Offering Price: $21.00 per Common Share.

Common SharesOffered:

10,000,000 Common Shares. If the Over-Allotment Option is exercised in full, theCompany will sell an additional 1,500,000 Common Shares. See “Plan of Distribution”.

Gross Proceeds: $210,000,000 or $241,500,000 if the Over-Allotment Option is exercised in full. See“Plan of Distribution”.

Over-Allotment Option: The Company has granted to the Underwriters the Over-Allotment Option pursuant towhich the Underwriters have the option to purchase up to an additional 1,500,000Common Shares (representing 15% of the number of Common Shares sold in theOffering) at a price equal to the Offering Price. The Over-Allotment Option isexercisable in whole or in part at any time on or before the date that is 30 days followingthe Closing Date. If the Underwriters exercise the Over-Allotment Option in full, thetotal Offering Price, Underwriters’ Commission and net proceeds to the Company will be$241,500,000, $13,282,500, and $228,217,500, respectively, See “Plan of Distribution”.

Common SharesOutstanding FollowingCompletion of theOffering and theConcurrent PrivatePlacement:

Prior to Completion of theOffering and the

Concurrent PrivatePlacement(1)

After Completion of theOffering and the

Concurrent PrivatePlacement(1)(2)

Common Shares (basic) . . . . . . . . . . . . . . . . 123,841,060 134,691,060Common Shares (diluted)(2) . . . . . . . . . . . . . 135,613,060 146,463,060

Notes:(1) Does not include any Common Shares issuable upon exercise of the Over-Allotment Option. If the Over-

Allotment Option is exercised in full, there will be an aggregate of 136,191,060 Common Shares (basic)and 147,963,060 Common Shares (diluted) outstanding upon completion of the Offering, the ConcurrentPrivate Placement and the issue of Common Shares pursuant to exercise of the Over-Allotment Option.

(2) Includes 11,772,000 Common Shares issuable pursuant to outstanding Options. See “Options to PurchaseCommon Shares”.

Closing: On or about November 23, 2010, subject to postponement as the Underwriters and theCompany may agree, but not later than December 15, 2010. See “Plan of Distribution”.

Concurrent PrivatePlacement:

In addition to, and apart from, the Offering, the Private Placees have each entered into asubscription agreement with the Company pursuant to which the Private Placees willpurchase, pursuant to the Concurrent Private Placement, an aggregate of 850,000 PrivatePlacement Shares at the Offering Price for gross proceeds to the Company of$17,850,000. No commission is payable to the Underwriters in connection with theConcurrent Private Placement.

The Private Placement Shares issued pursuant to the Concurrent Private Placement willbe subject to restrictions on resale for a period of four months under applicable securitieslegislation. The Concurrent Private Placement has been conditionally approved by theTSX. This prospectus does not qualify the distribution of the Private Placement Sharesissuable by the Company to the Private Placees pursuant to the Concurrent PrivatePlacement. See “Concurrent Private Placement” and “Directors and Executive Officers –Share Ownership by Directors and Officers”.

Use of Proceeds: The Company expects to receive net proceeds from the Offering of approximately$194,700,000 after deducting the Underwriters’ Commission and the expenses of the

15

Offering, estimated to be $3,750,000 and gross proceeds from the Concurrent PrivatePlacement of $17,850,000. The Company will receive net proceeds from the Offeringand gross proceeds from the Concurrent Private Placement of $242,317,500 if the Over-Allotment Option is exercised in full.

Based upon management’s current intentions, the Company expects to use thenet proceeds of the Offering and the gross proceeds from the Concurrent PrivatePlacement to fund a portion of its budgeted $425 million 2011 capital exploration anddevelopment program and, specifically, for the principal purposes of: (i) developmentand exploration drilling and well completions; (ii) expansion and equipping of facilitiesand pipelines; and (iii) acquisition of new land, seismic and geological data. Untilrequired for purposes of the Company’s 2011 capital exploration and developmentprogram, the net proceeds from the Offering and gross proceeds from the ConcurrentPrivate Placement will initially be applied to temporarily reduce outstandingindebtedness under the Tourmaline Revolving Facility, which will subsequently beredrawn and applied to fund the 2011 capital exploration and development program.

A summary of Tourmaline’s 2011 capital exploration and development budget isset forth below.

CapitalExpenditure

(MM$)

Development drilling and well completionsAlberta Deep Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 180.5Greater Peace River High . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66.0

246.5Exploration drilling and well completions . . . . . . . . . . . . . . . . . . . . . . . . . . 24.0Expansion and equipping of facilities and pipelines . . . . . . . . . . . . . . . . . . . 100.0Acquisition of new land and seismic and geological data . . . . . . . . . . . . . . . 54.5

425.0

The Company expects to fund the remainder of the 2011 capital exploration anddevelopment program from cash generated from its operations and draws under theCredit Facilities. The Company’s 2011 capital exploration and development program isdescribed under the heading “Description of the Business – 2011 Capital Exploration andDevelopment Program”.

Due to the nature of the oil and gas industry, budgets are regularly reviewed with respectto the success of past expenditures and other opportunities which become available to theCompany. Accordingly, while it is currently intended by management that the netproceeds of the Offering will be expended as set forth above, actual expenditures maydiffer from these amounts and allocations. Pending utilization of the net proceeds of theOffering, the funds will be deposited in bank accounts at Canadian chartered banks or beinvested in short-term bank securities or short-term Canadian or U.S. governmentsecurities pursuant to the Company’s investment policy. The Board of Directors mayamend the Company’s investment policy from time to time at its discretion. See “Use ofProceeds”.

Eligibility forInvestment:

In the opinion of Burnet, Duckworth & Palmer LLP, counsel to the Company, and Blake,Cassels & Graydon LLP, counsel to the Underwriters, on the date of the Offering,provided that the Common Shares are listed on a designated stock exchange (whichincludes the TSX), and subject to the more detailed discussion under “Eligibility forInvestment”, the Common Shares will on that date be a qualified investment under the

16

Tax Act for trusts governed by registered retirement savings plans, registered retirementincome funds, registered disability savings plans, deferred profit sharing plans, registerededucation savings plans and tax-free savings accounts as defined in the Tax Act. See“Eligibility for Investment”.

Risk Factors: An investment in the Common Shares should be considered speculative due to thenature of the Company’s involvement in the exploration for, and the acquisition,development and production of, crude oil and natural gas. The Company’s businessis subject to the risks normally encountered in the oil and gas industry such as:competition for prospective properties with companies having greater resources; themarketability of, and prices for, crude oil and natural gas; fluctuation in the market priceand demand for crude oil and natural gas; current global financial conditions; foreigncurrency risks; political, regulatory and legal issues in the jurisdictions in which theCompany operates; replacement of existing reserves on an ongoing basis; failure torealize anticipated benefits of acquisitions and dispositions; the availability of equipmentand access restrictions, including operating hazards and environmental risks and hazards;risks inherent in the exploration, development and production of crude oil and natural gaswhich may create liabilities to the Company in excess of the Company’s insurancecoverage; reliance on third party operators and key personnel; the potential losses whichwould stem from any disruptions in production, including work stoppages or disruptionsin the transportation network on which the Company is reliant; issuance of debt;maintenance of adequate internal control over financial process and reporting; litigationrisks; and management of growth related risks, including risks associated with theacquisition of oil and natural gas companies and assets. The reserve and recoveryinformation contained in this prospectus are estimates only and the actual production andultimate reserves recovered from the Company’s properties may be greater or less thanthe estimates contained in this prospectus. The success of further exploration ordevelopment projects cannot be assured. Investors must rely upon the ability, expertise,judgment, discretion, integrity and good faith of management when evaluating aninvestment in the Common Shares. There is currently no market through which theCommon Shares may be sold and investors may not be able to resell the Common Sharesqualified for distribution under this prospectus. These risk factors and those discussed ingreater detail in “Risk Factors” are not an exhaustive list of all risks associated with aninvestment in the Common Shares and should be read in conjunction with theinformation set forth elsewhere in this prospectus. See “Market for Securities” and “RiskFactors”.

17


Name, address and incorporation

Tourmaline Oil Corp. was incorporated under the ABCA under the name “1415065 Alberta Ltd.” on July 21,2008. On August 26, 2008, Tourmaline filed Articles of Amendment to change its name to “Tourmaline Oil Corp.”. OnOctober 24, 2008, Tourmaline filed Articles of Amendment to: (i) change its share provisions by creating a new classof shares designated as first preferred shares (the “First Preferred Shares”), issuable in series, and a new class ofshares designated as second preferred shares (the “Second Preferred Shares”), issuable in series, and amending theterms of the Common Shares; (ii) remove the “private company” restrictions; and (iii) change the minimum number ofdirectors of the Company from one to three. Tourmaline amalgamated with Pienza and Vigilant on January 1, 2010under the ABCA, continuing as Tourmaline Oil Corp.

Tourmaline’s head office is located at Suite 3700, 250 – 6th Avenue S.W., Calgary, Alberta T2P 3H7 and itsregistered office is located at Suite 1400, 350 – 7th Avenue S.W., Calgary, Alberta T2P 3N9.

Intercorporate relationships

The following diagram illustrates the intercorporate relationships among Tourmaline and its material subsidiaries,the percentage of votes attached to all voting securities of the subsidiaries beneficially owned, or controlled or directed,directly or indirectly, by Tourmaline and the jurisdiction of incorporation of each such subsidiary.

Altia Energy Ltd. (Alberta)

%6.09%001

Tourmaline Oil Corp.(Alberta)

Exshaw Oil Corp. (Alberta)

Altia Energy Ltd. (Alberta)

%6.09%001

Tourmaline Oil Corp.(Alberta)

Exshaw Oil Corp. (Alberta)

DESCRIPTION OF THE BUSINESS

Overview

Tourmaline is a Canadian intermediate crude oil and natural gas exploration and production company focused onlong-term growth through an aggressive exploration, development, production and acquisition program in the WCSB.Tourmaline commenced active operations in the fall of 2008 with the objective of building a successful Canadianintermediate crude oil and natural gas exploration, development and production company with a long-term businessstrategy similar to that of Duvernay and Berkley, companies previously founded and managed by certain key membersof Tourmaline’s senior management team. During the two-year period since commencing active operations,Tourmaline, through a series of strategic acquisitions, farm-ins and land acquisitions combined with its active capitalexploration and development program, has assembled an extensive undeveloped land position with a large, multi-yeardrilling inventory and operating control of important natural gas processing and transportation infrastructure in twocore long-term growth areas – the Alberta Deep Basin and the Greater Peace River High.

Management believes that the location, size, concentration and other attributes of the Company’s two core long-term growth areas provide an opportunity for the Company to achieve operating cost, reserve recovery, deliverabilityand production efficiencies through a large-scale, repeatable capital exploration and development program. Tourmalineis aggressively executing this program using principally 3D seismic data to identify drilling locations for multi-stagefracture stimulations of vertical and horizontal wells.

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As of the date of this prospectus, Tourmaline has:

Š approximately 1,356,000 gross (961,000 net) acres of land (approximately 80% of which is undeveloped);

Š in excess of 3,350 gross (2,400 net) drilling locations (based on two wells per section) and, in addition, up to1,000 gross potential horizontal drilling locations which are currently being assessed as part of the ongoingexploration and development drilling program;

Š in excess of 100 gross (65 net) recompletion locations; and

Š estimated current production of approximately 22,000 Boe/d and an estimated approximately 6,600 Boe/dbehind pipe awaiting tie-in.

Tourmaline’s management team has a track record of successfully identifying, acquiring and executing large,repeatable exploration and production drilling programs and has significant operating experience in the Company’score areas. The Company’s President and Chief Executive Officer, Mr. Rose, successfully founded and managed twoprevious companies: Berkley and, more recently, Duvernay. Duvernay commenced operations in September 2001 andwas sold in August of 2008. During this seven year period, Duvernay raised approximately $760 million in equitybefore its sale for approximately $6 billion ($5.6 billion equity value). Berkley commenced operations in 1993 and wassold in 2001. During this eight year period, Berkley raised approximately $482 million in equity before its sale forapproximately $1.55 billion ($1.22 billion equity value).

2011 Capital Exploration and Development Program

Tourmaline’s 2011 capital exploration and development program has been budgeted at $425 million based on,among other things, prevailing commodity prices and industry conditions. The program is primarily focused on drilling inthe Alberta Deep Basin and Greater Peace River High areas, with $270.5 million (64%) expected to be directed todevelopment and exploration drilling and well completions, $100 million (23%) expected to be directed to the expansionand equipping of facilities and pipelines and $54.5 million (13%) expected to be directed to the acquisition of new landand seismic and geological data. Tourmaline estimates that in 2011 it will drill up to 87 gross (67 net) wells, of which 51gross (43 net) wells are expected to be in the Alberta Deep Basin, 24 gross (16 net) wells are expected to be in the GreaterPeace River High and 12 gross (8 net) are expected to be exploration wells.

A summary of Tourmaline’s 2011 capital exploration and development program is set forth below.

2011 Capital Exploration and Development Program Summary

Wells(Gross)

Wells(Net)

CapitalExpenditure

(MM$)

Development drilling and well completionsAlberta Deep Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51 43 180.5Greater Peace River High . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 16 66.0

75 59 246.5Exploration drilling and well completions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 8 24.0Expansion and equipping of facilities and pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 100.0Acquisition of new land and seismic and geological data . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 54.5

87 67 425.0

The amount of capital the Company will expend for its 2011 capital exploration and development program and thenature of its expenditures may vary materially based on commodity prices, other industry conditions and theCompany’s drilling results as the year progresses.

If the Company is unable to complete the entire 2011 capital exploration and development program in 2011 asplanned, the balance of the program will be deferred to 2012 and the Company’s anticipated growth in its futureproduction, cash flows and reserves would be delayed.

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Business Strategy

Tourmaline’s long-term business strategy is to increase shareholder value by building an extensive asset base overtwo to three core exploration and production areas and exploiting and developing these areas to increase reserves,production and cash flows at an attractive return on invested capital. The Company seeks to execute this strategy by:

Š Aggressively Drilling and Developing Its Extensive Undeveloped Land Position. The Company intends toaggressively drill and develop its extensive undeveloped land position to maximize the value of its reserveand resource potential initially focusing on the drilling and development of its over 3,350 gross (2,400 net)drilling locations in the Alberta Deep Basin and the Greater Peace River High. Subject to industry conditions,ongoing drilling results and rig availability, Tourmaline initially plans to use eight operated drilling rigs toexecute its 2011 drilling program (with the potential of adding up to an additional four operated drilling rigslater in the year) and up to 12 operated drilling rigs to execute its 2012 drilling program. If drilling results aresuccessful, Tourmaline believes that additional rigs could be added to further expand these 2011 and 2012drilling programs. Assuming 12 operated drilling rigs are used by Tourmaline for a full year, Tourmalineanticipates that as many as 100 gross wells could be drilled in a year.

Š Adopting and Employing Advanced Drilling and Completion Techniques. Tourmaline’s management teamis focused on adopting and employing advanced drilling and completion techniques to maximize reserverecovery, deliverability, production and return on invested capital. These techniques have significantlyevolved over the last several years, resulting in increased initial production rates and recoverablehydrocarbons per well through the implementation of techniques such as using longer laterals and moretightly spaced multi-stage fracturing stimulation. Tourmaline continuously evaluates its drilling results andmonitors the results of other operators to improve operating practices and it expects its drilling andcompletion techniques will continue to evolve. Tourmaline believes that this continued evolution has thepotential to significantly enhance the Company’s ultimate reserve recovery, deliverability, production andrate of return on invested capital.

Š Enhancing Returns by Focusing on Operational and Cost Efficiencies. Tourmaline’s management team isfocused on continuous improvement in operating measures and has significant experience in successfullyexecuting large scale, repeatable capital exploration and development programs. Management believes that themagnitude and concentration of Tourmaline’s land position within its core long-term growth areas provides itwith the opportunity to capture economies of scale, including the ability to drill multiple wells from a singledrilling pad, utilize centralized production and fluid handling facilities and reduce the time and cost of rigmobilization.

Š Pursuing Strategic Acquisitions with Significant Potential Synergies. In the near-term, Tourmaline intends tocontinue to identify and seek to acquire additional land positions and producing assets in the Alberta DeepBasin and Greater Peace River High core areas to complement its existing operations. Over the long-term, theCompany expects to selectively target additional domestic basins that would allow it to employ its explorationand production strategy on large undeveloped land positions similar to those already accumulated.

Š Wildcat Exploration Drilling For New Pool Discoveries. Tourmaline intends to look for potentialopportunities to maximize long-term growth through wildcat exploration drilling for new pool discoveries,including in the Mississippian and Devonian formations. Tourmaline believes wildcat exploration drillingopportunities exist in the Alberta Deep Basin and Greater Peace River High core areas and, if suchopportunities are ultimately drilled and successful, they would provide the base for significant futuredevelopment projects and production growth. Management believes that Tourmaline has one of the fewexploration teams with deep Paleozoic experience and the Company has been acquiring prospective landsand delineating them with 3D seismic data since 2009. An extensive prospect inventory has been assembledand a wildcat drilling program is expected to commence in the second half of 2011. Tourmaline plans toallocate a modest portion of its budgeted capital exploration and development program each year towardswildcat exploration drilling.

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Competitive Advantages

Management believes Tourmaline has a number of competitive advantages that management expects will help theCompany successfully execute its long-term business strategy:

Š Extensive Undeveloped Land Position in Two Long-Term Growth Areas. Tourmaline’s current landposition in the Alberta Deep Basin and the Greater Peace River High play areas is approximately 1,282,000gross (896,000 net) acres. This represents one of the largest concentrated leasehold positions in the lowerCretaceous formation in the Alberta Deep Basin and a significant leasehold position in the Montney play areain the Greater Peace River High. A majority of the Company’s land position is in areas where there iscurrently significant industry drilling activity. Moreover, certain lower Cretaceous formations in the AlbertaDeep Basin are amenable to horizontal drilling and Tourmaline’s 2010 and 2011 capital exploration anddevelopment programs includes evaluating this potential, which has not yet been included in the Company’s3,100 gross drilling locations for the Alberta Deep Basin.

Š Large, Multi-Year Drilling Inventory. Tourmaline has in excess of approximately 3,350 gross (2,400 net)drilling locations, of which 3,100 are Alberta Deep Basin Cretaceous vertical wells (at two wells per section)and 250 are Montney horizontal wells in the Greater Peace River High. The Company plans to drill up to 87gross (67 net) wells in its long-term growth areas in 2011, which represents less than 3% of the Company’sgross drilling locations in these two areas.

Š Management Team with Demonstrated Operating and Acquisition Skills. Tourmaline’s senior managementteam has extensive expertise in the oil and natural gas industry as former senior management of Duvernay,Berkley and other Canadian exploration and production companies. The senior technical team has an averageof more than 25 years of oil and natural gas industry experience, including experience in multiple WCSBconventional and resource plays, as well as experience in other North American basins. The Companybelieves its management and technical team is one of the Company’s principal competitive strengths relativeto its industry peers due to the team’s track record in the identification, acquisition and execution ofexploration and production programs and opportunities. In addition, key members of the team possesssubstantial expertise in horizontal drilling, completion techniques and acquiring and managing largeexploration and development programs.

Š Incentivized Management Team. Tourmaline’s management team currently owns approximately 26% of theoutstanding Common Shares (approximately 25% immediately following the completion of the Offering andthe Concurrent Private Placement). In addition, the management team has Options to acquire an additional3,550,000 Common Shares. This ownership interest provides a significant incentive for the Company’smanagement to continue to grow the value of the Company’s business for the benefit of all shareholders.

Š Majority Operating Control of the Company’s Core Assets. In order to maintain better control over theCompany’s asset portfolio, Tourmaline has established a significant land position comprised primarily ofproperties that it operates. The Company currently operates approximately 80% of its 3,350 gross drillinglocations, or approximately 90% of its 2,400 net drilling locations. As of December 31, 2009, approximately81% of total proved reserves of Tourmaline and Exshaw (without reduction to reflect the 9.4% third-partyminority interest in Exshaw) were attributable to properties it operates. Approximately 90% of theCompany’s budgeted 2011 capital exploration and development program is related to operated wells, whichTourmaline anticipates will result in an increase in the percentage of its proved reserves attributable toproperties it operates. As of December 31, 2009, the Company’s average working interest in its operated andnon-operated drilling locations was 80% and 50%, respectively. Tourmaline believes controlling operationswill allow it to dictate the pace of development as well as better manage the cost, type and timing ofexploration and development activities. The Company believes that maintaining operational control over themajority of its land position will allow it to better pursue its strategies of enhancing returns throughoperational and cost efficiencies and maximizing hydrocarbon recovery through improvement of drilling andcompletion techniques. The Company also operates substantial natural gas gathering and processing facilitiesin the Alberta Deep Basin, controlling 200 MMcf/d of capacity, and similarly operates field processingfacilities in the Greater Peace River High with 30 MMcf/d of capacity.

Š Strong Balance Sheet. Tourmaline has and plans to maintain, through the application of budget controls andprudent financial management, a strong balance sheet with manageable debt levels relative to its market

21

capitalization and prospective cash flows to provide it with the financial flexibility to successfully execute itsaggressive growth strategy. No amounts will be drawn under the Credit Facilities on completion of theOffering and the Concurrent Private Placement. See “Use of Proceeds” and “Consolidated Capitalization”.

Š Focus on Operational Efficiencies and Cost Containment. Management believes that Tourmaline hasefficient operational cost containment as illustrated by its strong operating cost results of $7.94/Boe in thefourth quarter of 2009, $7.22/Boe in the first quarter of 2010, $6.98/Boe in the second quarter of 2010, and$6.24/Boe in the third quarter of 2010. By directing larger percentages of natural gas into operated facilities,continuing to bring on-stream productive new natural gas wells and optimizing existing facilities,management estimates that Alberta Deep Basin operating expenses will continue to be reduced over the next12 months. Similarly, G&A expenses per Boe, excluding interest, finance charges, stock-based compensationand capitalized G&A, have been trending downward as follows: fourth quarter of 2009, $1.74/Boe; firstquarter of 2010, $1.44/Boe; second quarter of 2010, $1.04/Boe; and third quarter of 2010, $0.95/Boe.

Three-Year History

General Development of the Business

Tourmaline commenced active operations in the fall of 2008 with the objective of building a successful Canadianintermediate crude oil and natural gas exploration, development and production company with a long-term businessstrategy similar to that of Duvernay and Berkley, companies previously founded and managed by certain key membersof Tourmaline’s senior management team. In October and December 2008, in the midst of the “world financial crisis”,Tourmaline completed its initial equity financings of approximately $326 million to provide it with the necessarycapital to commence active operations and the execution of its long-term business strategy. A key component ofTourmaline’s long-term business strategy has always been to be one of the lowest cost operators within its core areas.In Tourmaline’s view, striving to be a low cost operator is especially important in the current natural gas priceenvironment.

In a little less than two years, Tourmaline has grown into an intermediate crude oil and natural gas exploration andproduction company with current production estimated at approximately 22,000 Boe/d and an estimated 6,600 Boe/dbehind pipe awaiting tie-in. During this period, the Company has raised close to $1.0 billion through private placementequity financings, approximately $280.7 million of which was raised from Tourmaline’s directors, officers and theirassociates, and strategically completed 17 acquisitions to cost-effectively build its current production and extensiveland position. The acquisitions have been complemented by an aggressive exploration, development and productionprogram that is intended to be the Company’s primary long-term growth engine.

Overview of Acquisitions and Equity Financings

Two minor transactions were completed in the fall of 2008 which established Tourmaline’s presence in theAlberta Deep Basin, a play area where Tourmaline’s management and technical staff have extensive exploration andoperating experience and have had historical success. The first was the execution of a farm-in on approximately 100sections of land in the Ansel-Minehead area of the Alberta Deep Basin with a senior Canadian producer. The secondwas the acquisition of producing natural gas assets and associated undeveloped lands from another senior Canadianproducer in the Smoky-Horse area of the Alberta Deep Basin.

During the first half of 2009, Tourmaline took advantage of a relatively weak natural gas price environment andits strong balance sheet to complete a series of asset acquisitions in the Alberta Deep Basin. Management believes thatthe acquired assets have considerable additional reserve and production potential and the Company developed aparallel long-term plan to enhance and control the associated natural gas infrastructure facilities. Eight such assettransactions were completed during 2009, providing Tourmaline with a strong production base and an extensiveinventory of future potential drilling locations. To fund these acquisitions, the Company raised an additionalapproximately $348.4 million through two private placement equity financings in 2009.

Tourmaline established a second core exploration and production area in the Greater Peace River High area ofAlberta and NEBC during the second half of 2009 and early 2010 through the Pienza, Exshaw, Vigilant and AltiaAcquisitions. Pienza, Exshaw and Vigilant were acquired in 2009 and Altia was acquired in early 2010. Thesetransactions allowed Tourmaline to establish a strong position in the Montney play area, another play area where

22

Tourmaline’s management and technical staff have had extensive technical experience and have had historical success.Within the Greater Peace River High, Tourmaline has also assembled a large land position and drilling location inventoryin the Sunrise-Dawson area of NEBC, which is considered by management to be the optimum Montney play area in theentire NEBC Montney trend. To complement these acquisitions, Tourmaline also entered into a joint venture with aCanadian intermediate producer in the Elmworth area of Alberta, another attractive developing Montney play area withinthe Greater Peace River High. The Company is conducting delineation drilling during the remainder of 2010 in advance ofan anticipated more extensive natural gas development program at Elmworth in 2011.

The third main component of the Company’s Greater Peace River High core exploration and production area is theSpirit River area of Alberta. This area, acquired pursuant to the Exshaw Acquisition, features crude oil and natural gasaccumulations in 10 separate horizons, all of which have attractive future development inventories. The main pool, theCharlie Lake formation, has up to 30 vertical and 40 horizontal drilling locations, which are included in the Company’sdrilling location inventory.

Tourmaline completed a private placement equity financing in March of 2010, raising approximately $224 million.This financing provided the Company with the funds required to pursue additional, sizeable asset acquisitions that wereavailable for sale during the first half of 2010.

In June of 2010, Tourmaline completed the Greater Hinton Acquisition. Pursuant to the Greater Hinton Acquisition,Tourmaline acquired from a senior Canadian producer approximately 4,000 Boe/d of production and 462 gross (346 net)sections of developed and undeveloped lands in the Alberta Deep Basin. The Greater Hinton Acquisition consolidated theCompany’s position as one of the largest producers and land and drilling inventory holders in the entire Alberta Deep Basin.

The following table summarizes the Company’s significant acquisitions.

Significant Acquisition Summary

Date Acquisition Areas

PurchasePrice

(MM$)(1)Production(2)

(Boe/d)

Undeveloped Land

GrossAcres

NetAcres

April 30, 2009 Alberta Deep Basin Acquisition Hinton / Musreau / Narraway $103.0 2,350 86,072 27,466August 28, 2009 Wild River Acquisition Wild River, Harley, Olsen and

Sundance $145.9 2,550 44,196 24,016September 15, 2009 Pienza Acquisition(3) Sunrise NEBC $ 50.0 350 23,348 15,980November 10, 2009 Exshaw Acquisition Peace River Arch $131.8 2,510 56,960 41,718November 10, 2009 Vigilant Acquisition(3) Musreau / Chime / Whitecourt $ 47.5 650 92,734 88,538January 14, 2010 Altia Acquisition Dawson NEBC $100.8 1,500 122,600 56,980June 1, 2010 Greater Hinton Acquisition Greater Hinton $275.0 4,000 266,849 204,560

$854.0 13,910 692,759 459,258

Notes:(1) These amounts reflect the purchase price paid in cash and/or Common Shares and associated transaction costs.(2) Estimated production as at the effective date of the acquisition.(3) Subsequent to the Pienza Acquisition and Vigilant Acquisition, Tourmaline amalgamated with Pienza and Vigilant on January 1, 2010 under the

ABCA, continuing as Tourmaline Oil Corp.

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The following table summarizes the equity financings completed by the Company since commencement of activeoperations as well as the Company insider, employee and associate participation in such equity financings.

Summary of Equity Financings

Financings Insider, Employee and Associate Participation(7)

DateSharesIssued

Total GrossProceeds Gross Subscriptions

Percentage ofGross Proceeds

October 27, 2008 . . . . . . . . . . . . . . . . . . . . . . . 50,500,000(1) $301,000,000 $147,000,000 48.8%December 17, 2008 . . . . . . . . . . . . . . . . . . . . . . 2,500,000(2) $ 25,000,000 $ 12,500,000 50.0%May 28, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . 14,000,000(3) $140,000,000 $ 30,000,000 21.4%November 10, 2009 . . . . . . . . . . . . . . . . . . . . . . 13,543,624(4) $208,404,360 $ 47,904,360 23.0%March 19, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . 11,950,000(5) $223,920,000 $ 36,720,000 16.4%August 12, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . 1,150,000(6) $ 25,300,000 $ 6,600,000 26.1%

93,643,624 $923,624,360 $280,724,360 30.4%

Notes:(1) Private placement of 15,000,000 Common Shares at $3.50 per share and 35,500,000 Common Shares at $7.00 per share.(2) Private placement of 2,500,000 Flow-Through Shares at $10.00 per share.(3) Private placement of 14,000,000 Common Shares at $10.00 per share.(4) Private placement of 11,793,624 Common Shares at $15.00 per share and 1,750,000 Flow-Through Shares at $18.00 per share.(5) Private placement of 9,500,000 Common Shares at $18.00 per share and 2,450,000 Flow-Through Shares at $21.60 per share.(6) Private placement of 1,150,000 Flow-Through Shares at $22.00 per share.(7) Represents percentage of insider, employee and associate participation for the total amount raised by the Company, which has been calculated

based on the percentage of Common Shares issued to directors, officers, employees and other service providers of the Company and certainfamily, friends and business associates of the foregoing relative to the total number of Common Shares issued in each financing.

DESCRIPTION OF CORE LONG-TERM GROWTH AREAS

The following is a description of Tourmaline’s two core long-term growth areas – the Alberta Deep Basin and theGreater Peace River High.

Alberta Deep Basin Core Area

The Alberta Deep Basin core area is located approximately 250 kilometres west of Edmonton, Alberta and is amulti-objective tight natural gas sand play area with up to 15 separate lower Cretaceous tight natural gas sandreservoirs. Tourmaline’s target exploration and production area is in the centre of the Alberta Deep Basin where theentire lower Cretaceous stratigraphic section is gas saturated. The primary vehicle for accessing these extensivereserves in stacked sandstones is multi-stage fracture stimulation in vertical well-bores. Tourmaline uses 3D seismicdata to select the majority of its drilling locations, and management believes it is an industry leader in adopting andadapting the improving drilling and completion technologies. The majority of the Company’s working interest landshave already received approval for down-spacing at four vertical wells per section.

Certain formations within the lower Cretaceous stack of tight sand reservoirs in the Alberta Deep Basin are moreamenable to horizontal drilling (Cardium, Wilrich, Second Specks, Nikinassin). Accordingly, each section in theAlberta Deep Basin core area may include one or two targeted multi-phase stimulated horizontal wells in theCompany’s long-term development plan. Management estimates that up to 1,000 gross potential horizontal drillinglocations exist in the Alberta Deep Basin which are currently being assessed as part of the ongoing drilling program.These potential horizontal drilling locations have not been included in the Company’s drilling locations inventory.Future evaluation of these “embedded” resource plays is an important component of the 2011 capital exploration anddevelopment program, with several horizontal wells planned. When developed, these embedded resource plays willutilize the natural gas infrastructure being constructed for vertical well development and downspacing.

The assets acquired pursuant to the Greater Hinton Acquisition in June of 2010 consisted of production ofapproximately 4,000 Boe/d, proved plus probable reserves of approximately 30 MMboe and significant workinginterests in over 462 sections of land. Management believes the Greater Hinton Acquisition further solidified theCompany as one of the leading natural gas producers in the Alberta Deep Basin.

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Tourmaline has ownership interests in four natural gas plants in the Alberta Deep Basin, two of which, the WildRiver 14-20 plant (70% owned) and the Hinton 6-32 gas plant (100% owned), are operated by Tourmaline. In addition,Tourmaline owns and operates a substantial compression and dehydration facility at Horse capable of processingapproximately 50 MMcf/d of natural gas. Tourmaline’s goal is to be the lowest-cost, most efficient operator in theAlberta Deep Basin, and during the next 12 to 18 months, the Company plans to optimize and systematically reducecosts of operating the assets acquired in 2009 as well as the new properties being developed.

Tourmaline has assembled a land portfolio in the Alberta Deep Basin that is more than three times larger than thatheld by Duvernay at the time of its sale (approximately 1,550 gross sections at an average 73% working interestcompared to approximately 450 gross sections). This land portfolio equates to approximately 3,100 drilling locationsbased on only two wells per section. The Company also has a recompletion inventory of over 100 wells in the AlbertaDeep Basin.

In the Alberta Deep Basin, Tourmaline drilled 29 natural gas wells in 2009, and has drilled 27 natural gas wells aswell as four recompletions in 2010. Tourmaline’s net production in the Alberta Deep Basin grew through 15,000 Boe/din June 2010 and is currently estimated at approximately 17,500 Boe/d with further production growth anticipatedthrough the balance of the year. The Company estimates that it currently has approximately 6,600 Boe/d behind pipeawaiting tie-in. Year-end 2009 proved plus probable reserves were 42.2 MMboe in the Alberta Deep Basin, with only100 of the 3,100 drilling locations recognized in the Reserve Reports.

Greater Peace River High Core Area

Tourmaline has assembled its second core exploration and production area in the Greater Peace River Highextending from Grande Prairie, Alberta to approximately 30 kilometres southwest of Fort St. John, NEBC, where theprimary focus is liquids rich natural gas in the Triassic Montney formation. The Company has assembled this largeMontney position primarily through the acquisitions completed in 2009 and early 2010. In NEBC, Tourmaline has aninventory of over 150 horizontal Montney development drilling locations in the Sunrise/Dawson area, making theCompany one of the largest participants in this resource play. Management believes that this is the optimum area forpursuit of Triassic Montney natural gas within the entire play as this is where the Montney pay section is the thickest,most over-pressured and offers the highest deliverability. Complementing this growing Montney drilling inventory inNEBC is a series of high deliverability/low operating cost sweet Mississippian Kiskatinaw and Wabamun natural gaspools. Management believes that these deeper pools also have considerable exploration and production potential andwill be the subject of ongoing exploration and development in 2010 and 2011.

In the Alberta portion of the Greater Peace River High area, Tourmaline has secured access to 80 gross (38.75 net)sections of prospective acreage in the rapidly developing Montney play at Elmworth through a joint venture with aCanadian intermediate oil and gas company. There are in excess of 100 drilling locations on this land block which areincluded in the Company’s drilling inventory. Three Tourmaline-operated horizontal delineation wells are planned forlate 2010 or early 2011 in advance of a more substantial development drilling plan in 2011. Complementing thisMontney project in Alberta is the Company’s producing complex at Spirit River, Alberta. The majority of theproduction at Spirit River is derived from oil and natural gas-charged reservoirs of the Triassic Charlie Lake formation.This area, currently producing approximately 2,300 Boe/d, has a large inventory of vertical and horizontal developmentdrilling prospects in the Charlie Lake formation as well as attractive plays in several other formations.

Industry participants have been pursuing Triassic Montney plays and reservoirs in the WCSB for over fourdecades. Exploration and production of the Montney has evolved over time from conventional reservoirs in the southeast portion of the play area in Alberta to unconventional Montney reservoirs in the Peace River Arch area of Albertaand NEBC. Technological developments, including the drilling of horizontal multi-stage fracture stimulation wells,have allowed access to the thickest, highest pressured and highest deliverability Montney in the NEBC play area. It isin this Groundbirch/Sunrise/Dawson area of the Peace River Arch where senior management of Tourmaline gainedextensive experience with Duvernay and where Tourmaline has concentrated its exploration and production program.

In the Greater Peace River High, Tourmaline has drilled 15 Montney multi-stage fracture stimulated horizontalnatural gas wells, two Charlie Lake horizontal oil wells and one vertical oil well to date in 2010 with an additional sixto eight Montney horizontal wells planned for the balance of 2010. In addition, Tourmaline plans to complete theconstruction of an operated natural gas processing facility and gathering system. Tourmaline’s net production in theGreater Peace River High is currently estimated at approximately 4,500 Boe/d. Year-end 2009 proved plus probablereserves were 17.1 MMboe in the Greater Peace River High.

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RECENT DEVELOPMENTS

Deep Basin West Acquisition

Overview

On November 1, 2010, pursuant to a purchase and sale agreement dated October 8, 2010, as amendedNovember 1, 2010, with an industry participant (the “Vendor”), Tourmaline acquired certain petroleum and naturalgas properties and related assets in the Alberta Deep Basin (the “Acquired Assets”) for a cash purchase price ofapproximately $52 million, before closing adjustments of approximately $2.1 million, and applicable goods andservices tax. The purchase price for the Acquired Assets was funded by a draw under the Tourmaline RevolvingFacility. See “Consolidated Capitalization”, “Use of Proceeds” and “Relationship Between the Company and Certainof the Underwriters”. Tourmaline estimates that the Acquired Assets produced an average of approximately 8.9MMcfe/d of crude oil, natural gas and NGL (approximately 1,500 Boe/d – 97.5% natural gas) in September 2010 andinclude an undeveloped land base and ownership in area infrastructure.

The Deep Basin West Acquisition is not a “significant acquisition” for the purposes of Part 8 of NI 51-102.

Benefits of the Deep Basin West Acquisition

The Deep Basin West Acquisition is expected to build on Tourmaline’s expanding footprint in the Alberta DeepBasin.

The following are certain key attributes of the Acquired Assets:

Š current production estimated at approximately 8.7 MMcf/d of natural gas and 38 Bbls/d of crude oil andNGL production from the Notikewin, Fahler, Dunvegan and Cardium formations;

Š 143,000 net undeveloped acres for development of 150 gross drilling locations; and

Š significant ownership in area infrastructure is expected to enhance Tourmaline’s ability to translate theinventory of drilling locations to value, as well as capitalize on additional opportunities in the area.

The lands, natural gas, crude oil and NGL production and drilling locations acquired pursuant Deep Basin WestAcquisition have been included in the Company’s current total information provided elsewhere in this prospectus.

While management expects that the Company will receive the benefits noted above, the Deep Basin WestAcquisition exposes the Company to additional risks, including the risk that the Company will fail to realize theanticipated benefits of the Deep Basin West Acquisition. See “Risk Factors—Risks Relating to the Deep Basin WestAcquisition” for a further discussion of certain of the risks associated with the Deep Basin West Acquisition.

Liability Arrangements for the Deep Basin West Acquisition

In connection with the Deep Basin West Acquisition, the Vendor has agreed to indemnify Tourmaline for a period of12 months from closing in respect of certain losses that may arise out of Tourmaline’s acquisition of the Acquired Assetswhich pertain, directly or indirectly, to the Acquired Assets and occur or accrue prior to the effective date of the DeepBasin West Acquisition. In a manner consistent with typical industry practice, Tourmaline has agreed to indemnify theVendor for all liabilities which relate to the Acquired Assets that accrue on or subsequent to the effective date of the DeepBasin West Acquisition, except where those liabilities are caused by the gross negligence or wilful misconduct of theVendor. Tourmaline has also expressly assumed all past, present and future environmental liabilities for matters relating tothe Acquired Assets and has agreed to indemnify the Vendor for all liabilities it may incur in respect of environmentalmatters relating to the Acquired Assets, except where the liability relates to a breach of the Vendor’s limitedrepresentation and warranty in respect of certain environmental matters.

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STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

Date of Statement

The statement of reserves data and other oil and gas information set forth below is dated October 13, 2010 andeffective as at December 31, 2009.

Disclosure of Reserves Data

The reserves data set forth below is based upon the Reserve Reports. The Reserve Reports evaluate the crude oil,NGL and natural gas reserves of Tourmaline (evaluated by GLJ in the GLJ Tourmaline Reserve Report) and Exshaw(evaluated by AJM in the AJM Exshaw Reserve Report, without reduction to reflect the 9.4% third-party minorityinterest in Exshaw) and the net present values of future net revenue for these reserves using forecast prices and costs.The Reserve Reports have been prepared in accordance with the standards contained in the COGE Handbook and thereserve definitions contained in NI 51-101 and the COGE Handbook. Additional information not required byNI 51-101 has been presented to provide continuity and additional information which Tourmaline believes is importantto the readers of this prospectus. GLJ and AJM were engaged to provide evaluations of proved and proved plusprobable reserves and no attempt was made to evaluate possible reserves.

All of Tourmaline’s and Exshaw’s reserves are in Canada and, more specifically in the provinces of Alberta andBritish Columbia.

The applicable Reports on Reserves Data by Independent Qualified Reserves Evaluators in Form 51-101F2 andthe Reports of Management and Directors on Oil and Gas Disclosure in Form 51-101F3 are attached as Appendices Cthrough F to this prospectus.

There are numerous uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and thefuture cash flows attributed to such reserves. The reserve and associated cash flow information set forth in thisprospectus are estimates only. In general, estimates of economically recoverable oil and natural gas reserves and thefuture net cash flows therefrom are based upon a number of variable factors and assumptions, such as historicalproduction from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures,marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies andfuture operating costs, all of which may vary materially from actual results. For those reasons, estimates of theeconomically recoverable oil and natural gas reserves attributable to any particular group of properties, classification ofsuch reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared bydifferent engineers, or by the same engineers at different times, may vary. The Company’s actual production, revenues,taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof andsuch variations could be material.

The information relating to the crude oil and natural gas reserves of Tourmaline and Exshaw contains forward-looking statements relating to future net revenues, forecast capital expenditures, future development plans and costsrelated thereto, forecast operating costs, anticipated production and abandonment costs. See “Forward-LookingStatements”, “Certain Reserves Data Information”, “Industry Conditions” and “Risk Factors – Reserves Estimates”.

Tourmaline and Exshaw Combined Reserves

The reserves data for the Tourmaline and Exshaw combined reserves set forth below has been derived fromthe Reserve Reports and reflects 100% of Exshaw’s reserves without reduction to reflect the 9.4% third-partyminority interest in Exshaw.

The reserves data for the Tourmaline and Exshaw combined reserves set forth below has been prepared by GLJ andis based on the data contained in the Reserve Reports adjusted to apply certain of GLJ’s assumptions and methodologiesused in the preparation of the GLJ Tourmaline Reserve Report to the AJM Exshaw Reserve Report. Accordingly, thecombined reserves information for Tourmaline and Exshaw below varies from the reserve information that would bederived from a simple arithmetic summation of the GLJ Tourmaline Reserve Report and the AJM Exshaw ReserveReport.

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Reserves and Future Net Revenue Data (Forecast Prices and Costs)

Summary of Crude Oil and Natural Gas Reserves andNet Present Values of Future Net Revenue



Reserves Category

CompanyGross

(Mbbls)

CompanyNet

(Mbbls)

CompanyGross

(MMcf)

CompanyNet

(MMcf)

CompanyGross

(Mbbls)

CompanyNet

(Mbbls)

Proved Developed Producing . . . . . . . . . . . . . . . 1,070 877 90,834 81,106 1,006 642Proved Developed Non-Producing . . . . . . . . . . . 82 63 20,479 18,609 254 183Proved Undeveloped . . . . . . . . . . . . . . . . . . . . . . 716 552 74,099 63,689 847 583

Total Proved Reserves . . . . . . . . . . . . . . . . . . . . . 1,869 1,492 185,412 163,403 2,107 1,409Total Probable Reserves . . . . . . . . . . . . . . . . . . . 2,871 2,192 121,704 101,520 1,355 896

Total Proved Plus Probable Reserves . . . . . . . 4,740 3,684 307,116 264,923 3,462 2,305


Before Future Income Taxes Discounted at(%/year)





Non-Producing . . . . . . . . . . . . . 123,557 95,613 77,963 65,958 57,314 103,823 81,671 67,663 58,064 51,079 3.88 23.29Proved Undeveloped . . . . . . . . . . . 252,121 152,430 93,534 56,199 31,178 188,992 108,136 60,309 29,998 9,733 1.33 7.96


Total Proved Plus ProbableReserves . . . . . . . . . . . . . . . . . . 1,647,538 1,100,488 801,432 617,670 495,169 1,383,100 927,994 677,848 523,258 419,717 2.66 15.98

Total Future Net Revenue ($000s)(Undiscounted)


Reserves Category Revenue RoyaltiesOperating

CostsDevelopment

Costs

Abandonmentand

ReclamationCosts

Future NetRevenueBefore

DeductingFutureIncomeTax

Expenses

FutureIncomeTax

Expenses

Future NetRevenueAfterFutureIncomeTax

Expenses

Proved . . . . . . . . . . . . . . . . . . . . . 1,789,433 240,309 396,830 228,865 20,188 903,241 82,863 820,378Proved Plus Probable . . . . . . . . . 3,269,268 496,966 708,109 389,905 26,750 1,647,538 264,439 1,383,100

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Future Net Revenueby Production Group


Reserves Category Production Group

Future Net RevenueBefore Income Taxes

(discounted at10%/year)

($000s)

Unit Value(discounted at10%/ year)

($/Mcfe) ($/Boe)

Proved Reserves Light and Medium Crude Oil . . . . . . . . . . . . . . . . . . . . . . . . . 81,727 5.06 30.34Natural Gas (including by-products but excluding

solution gas) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 429,097 2.61 15.64

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 510,824 2.83 16.95Proved Plus Probable Light and Medium Crude Oil . . . . . . . . . . . . . . . . . . . . . . . . . 194,825 4.53 27.18

Natural Gas (including by-products but excludingsolution gas) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 606,607 2.35 14.12

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 801,432 2.66 15.98

Tourmaline Stand Alone Reserves

The reserve data for Tourmaline set forth below has been derived from the GLJ Tourmaline Reserve Report anddoes not include Exshaw’s reserves evaluated in the AJM Exshaw Reserve Report.





Reserves Category

CompanyGross

(Mbbls)


CompanyGross

(MMcf)


CompanyGross

(Mbbls)


Proved Developed Producing . . . . . . . . . 305 228 77,560 71,365 894 579Proved Developed Non-Producing . . . . . 0 0 18,704 17,270 239 175Proved Undeveloped . . . . . . . . . . . . . . . . 50 42 62,353 55,055 747 522

Total Proved Reserves . . . . . . . . . . . . . . . 355 270 158,617 143,690 1,880 1,276Total Probable Reserves . . . . . . . . . . . . . 157 121 96,432 83,854 1,147 774

Total Proved Plus ProbableReserves . . . . . . . . . . . . . . . . . . . . . . . . 512 391 255,048 227,545 3,027 2,050


Before Future Income Taxes Discounted At(%/year)





Non-Producing . . . . . . . . . . . . . . 113,410 87,243 70,910 59,912 52,056 113,410 87,243 70,910 59,912 52,056 3.87 23.23Proved Undeveloped . . . . . . . . . . . 205,012 117,641 66,878 35,252 14,427 158,536 88,925 48,001 22,181 4,974 1.14 6.87


Total Proved Plus ProbableReserves . . . . . . . . . . . . . . . . . . 1,265,106 817,832 581,057 439,144 346,310 1,097,406 718,738 516,080 393,200 311,977 2.40 14.40

29

Total Future Net Revenue ($000s)(undiscounted)



CostsDevelopment

Costs

Abandonmentand

ReclamationCosts


DeductingFutureIncomeTax

Expenses

FutureIncomeTax

Expenses


Expenses

Proved . . . . . . . . . . . . . . . . . . . 1,437,604 164,971 314,176 184,981 14,365 759,110 46,477 712,634Proved Plus Probable . . . . . . . . 2,418,000 297,931 524,668 311,589 18,706 1,265,106 167,700 1,097,406




Future Net RevenueBefore Income

Taxes (discounted at10%/year)

($000s)

Unit Value(discounted at10%/year)

($/Mcfe) ($/Boe)

Proved Reserves Light and Medium Crude Oil . . . . . . . . . . . . . . . . . . . . . . 12,105 5.55 33.28Natural Gas (including by-products but excluding

solution gas) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 397,426 2.64 15.81

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 409,531 2.68 16.06

Proved Plus Probable Light and Medium Crude Oil . . . . . . . . . . . . . . . . . . . . . . 16,810 5.34 32.07Natural Gas (including by-products but excluding

solution gas) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 564,248 2.36 14.16

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 581,057 2.40 14.40

Exshaw Stand Alone Reserves

The reserves data for Exshaw set forth below has been derived from the AJM Exshaw Reserve Report. TheExshaw reserves data reflects 100% of Exshaw’s reserves and has not been reduced to reflect the 9.4% third-party minority interest in Exshaw.





Reserves Category

CompanyGross

(Mbbls)


CompanyGross

(MMcf)


CompanyGross

(Mbbls)


Proved Developed Producing . . . . . . . . . . . . . . . . . . 764.8 638.7 13,159.2 9,444.9 111.2 62.5Proved Developed Non-Producing . . . . . . . . . . . . . . 82.3 55.7 1,728.2 1,292.3 14.8 8.5Proved Undeveloped . . . . . . . . . . . . . . . . . . . . . . . . . 666.2 508.2 11,745.0 9,080.6 99.7 61.6

Total Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . 1,513.2 1,202.6 26,632.4 19,817.8 225.7 132.5Total Probable Reserves . . . . . . . . . . . . . . . . . . . . . . 2,713.6 1,997.5 25,270.6 17,534.8 208.4 122.1

Total Proved Plus Probable Reserves . . . . . . . . . . 4,226.8 3,200.1 51,903.0 37,352.6 434.1 254.6

30

Net Present Values of Future Net Revenue ($000s)

Before Future Income Taxes DiscountedAt

(%/year)After Future Income Taxes Discounted at

(%/year)

UnitValueBeforeIncomeTax

Discountedat 10%/year


Proved Developed Producing . . . . . . . . . . . 85,488 74,157 65,702 59,185 54,022 85,488 74,157 65,702 59,185 54,022 4.81 28.88Proved Developed Non-Producing . . . . . . . 9,482 7,779 6,521 5,564 4,817 9,482 7,779 6,521 5,564 4,817 3.89 23.32Proved Undeveloped . . . . . . . . . . . . . . . . . . 49,207 35,694 26,850 20,688 16,190 40,238 27,834 19,902 14,502 10,645 2.15 12.89

Total Proved Reserves . . . . . . . . . . . . . . . . 144,177 117,630 99,073 85,436 75,029 135,208 109,770 92,126 79,250 69,483 3.56 21.36Total Probable Reserves . . . . . . . . . . . . . . . 255,536 173,315 124,990 94,168 73,330 194,897 130,464 93,054 69,414 53,555 4.13 24.79

Total Proved Plus Probable Reserves . . . 399,713 290,946 224,062 179,605 148,359 330,105 240,233 185,180 148,664 123,038 3.86 23.15

Total Future Net Revenue (MM$)(undiscounted)



CostsDevelopment

Costs

Abandonmentand

ReclamationCosts

OtherRevenue


DeductingFuture

Income TaxExpenses

FutureIncomeTax

Expenses


Expenses

Proved . . . . . . . . . . . . . 355.5 82.2 82.4 43.9 5.7 2.9 144.2 9.0 135.2Proved Plus

Probable . . . . . . . . . . 897.5 231.3 183.1 78.3 7.9 2.9 399.7 69.6 330.1




Future Net RevenueBefore Income Taxes

(discounted at10%/year)

($000s)

Unit Value(discounted at10%/year)

($/Mcfe) ($/Boe)

Proved Reserves Light and Medium Crude Oil . . . . . . . . . . . . . . . . . . . . . . 68,960 4.80 28.77Natural Gas (including by-products but excluding

solution gas) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30,112 2.24 13.44

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99,073 3.56 21.36

Proved Plus Probable Light and Medium Crude Oil . . . . . . . . . . . . . . . . . . . . . . 183,855 4.56 27.39Natural Gas (including by-products but excluding

solution gas) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40,208 2.26 13.55

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 224,062 3.86 23.15

Notes to Reserves Data Tables:1. Columns may not add due to rounding.2. Tourmaline has no unconventional reserves (bitumen, synthetic crude oil, natural gas from coal or heavy oil).3. The crude oil, NGL and natural gas reserve estimates in this prospectus are based on the definitions and guidelines contained in the COGE

Handbook. A summary of those definitions are set forth in “Glossary of Selected Oil and Gas Terms.”

31

GLJ Tourmaline Reserve Report Pricing AssumptionsSummary of Pricing and Inflation Rate Assumptions

Forecast Prices and Costs(1)Crude Oil and Natural Gas Liquids Pricing

Year Inflation (2)

Bank ofCanadaAverageNoon

ExchangeRate

$US/$Cdn(3)

NYMEX WTINear Month

FuturesContract CrudeOil at Cushing

Oklahoma

ICEBRENT

Near MonthFuturesContractCrude OilFOB NorthSea ThenCurrent$Cdn/Bbl

Light,Sweet

Crude Oil(40 API,0.3%S) atEdmonton

ThenCurrent$Cdn/Bbl

BowRiver

Crude OilStream

Quality atHardistyThen

Current$Cdn/Bbl

WCSStreamQuality

at HardistyThen

Current$Cdn/Bbl

HeavyCrude Oil

Proxy(12 API) atHardistyThen

Current$Cdn/Bbl

LightCrude Oil(35 API,1.2%S) atCromerThen

Current$Cdn/Bbl

MediumCrude Oil(29 API,2.0%S) atCromerThen

Current$Cdn/Bbl

Alberta Natural Gas Liquids(Then Current Dollars)

Constant2010$

$US/Bbl

ThenCurrent

$US/Bbl

SpecEthane

$Cdn/Bbl

EdmontonPropane$Cdn/Bbl

EdmontonButane

$Cdn/Bbl

EdmontonPentanes

Plus$Cdn/Bbl

2010 Q1 . . . . . . . . . . . 2.0 0.950 80.00 80.00 78.50 83.26 71.61 70.76 64.99 78.27 76.60 18.88 52.46 64.11 84.932010 Q2 . . . . . . . . . . . 2.0 0.950 80.00 80.00 78.50 83.26 71.61 70.76 64.99 78.27 76.60 19.25 52.46 64.11 84.932010 Q3 . . . . . . . . . . . 2.0 0.950 80.00 80.00 78.50 83.26 71.61 70.76 64.99 78.27 76.60 19.25 52.46 64.11 84.932010 Q4 . . . . . . . . . . . 2.0 0.950 80.00 80.00 78.50 83.26 71.61 70.76 64.99 78.27 76.60 22.70 52.46 64.11 84.932010 Full Year . . . . . . 2.0 0.950 80.00 80.00 78.50 83.26 71.61 70.76 64.99 78.27 76.60 20.02 52.46 64.11 84.932011 . . . . . . . . . . . . . . 2.0 0.950 81.37 83.00 81.50 86.42 72.59 71.70 65.24 80.37 78.64 22.88 54.45 66.54 88.152012 . . . . . . . . . . . . . . 2.0 0.950 82.66 86.00 84.50 89.58 73.45 72.51 65.33 83.31 80.62 23.24 56.43 68.98 91.372013 . . . . . . . . . . . . . . 2.0 0.950 83.87 89.00 87.50 92.74 74.19 73.20 65.26 86.25 82.54 23.43 58.42 71.41 94.592014 . . . . . . . . . . . . . . 2.0 0.950 85.00 92.00 90.50 95.90 76.72 75.68 67.52 89.19 85.35 23.79 60.42 73.84 97.822015 . . . . . . . . . . . . . . 2.0 0.950 85.00 93.84 92.34 97.84 78.27 77.20 68.90 90.99 87.07 24.15 61.64 75.33 99.792016 . . . . . . . . . . . . . . 2.0 0.950 85.00 95.72 94.22 99.81 79.85 78.75 70.32 92.82 88.83 25.06 62.88 76.85 101.812017 . . . . . . . . . . . . . . 2.0 0.950 85.00 97.64 96.14 101.83 81.46 80.33 71.76 94.70 90.63 26.88 64.15 78.41 103.862018 . . . . . . . . . . . . . . 2.0 0.950 85.00 99.59 98.09 103.88 83.11 81.95 73.22 96.61 92.46 28.84 65.45 79.99 105.962019 . . . . . . . . . . . . . . 2.0 0.950 85.00 101.58 100.08 105.98 84.78 83.59 74.72 98.56 94.32 29.46 66.77 81.60 108.102020+ . . . . . . . . . . . . . 2.0 0.950 85.00 +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr

Natural Gas and Sulphur Pricing

Year

MidwestPrice @ChicagoThen

Current$US/

MMbtu

AECO/NIT SpotThen

Current$Cdn/MMbtu

Alberta Plant GateSaskatchewan Plant

Gate British Columbia

SulphurFOB

Vancouver$US/LT

AlbertaSulphurat PlantGate

$Cdn/LT

Henry Hub NymexNear Month Contract Spot

ARP $/MMbtu

Aggregator$/MMbtu

Alliance$/MMbtu

SaskEnergy$/MMbtu

Spot$/MMbtu

Sumas Spot$US/mmbtu

WestcoastStation 2$/mmbtu

SpotPlantGate

$/mmbtu

Constant2010 $

$US/MMbtu

ThenCurrent

$US/MMbtu

Constant2010 $

$/MMbtu

ThenCurrent$/MMbtu

2010 Q1 . . . . . . . 5.60 5.60 5.70 5.63 5.43 5.43 5.26 5.20 4.59 5.36 5.55 5.20 5.43 5.23 35.00 -6.162010 Q2 . . . . . . . 5.75 5.75 5.85 5.74 5.53 5.53 5.37 5.30 4.75 5.47 5.66 5.35 5.54 5.34 35.00 -6.162010 Q3 . . . . . . . 5.85 5.85 5.95 5.74 5.53 5.53 5.37 5.30 4.85 5.47 5.66 5.45 5.54 5.34 35.00 -6.162010 Q4 . . . . . . . 6.80 6.80 6.90 6.74 6.52 6.52 6.33 6.25 5.81 6.43 6.66 6.40 6.54 6.33 35.00 -6.162010 Full Year . . 6.00 6.00 6.10 5.96 5.75 5.75 5.58 5.51 5.00 5.68 5.88 5.60 5.76 5.56 35.00 -6.162011 . . . . . . . . . . 6.86 7.00 7.10 6.79 6.45 6.58 6.38 6.30 6.02 6.48 6.71 6.45 6.59 6.38 50.00 9.632012 . . . . . . . . . . 6.82 7.10 7.20 6.89 6.42 6.68 6.48 6.40 6.12 6.58 6.81 6.55 6.69 6.49 60.00 20.162013 . . . . . . . . . . 6.74 7.15 7.25 6.95 6.34 6.73 6.53 6.45 6.17 6.63 6.87 6.60 6.75 6.54 75.00 35.952014 . . . . . . . . . . 6.79 7.35 7.45 7.05 6.32 6.84 6.63 6.55 6.37 6.73 6.97 6.80 6.85 6.64 75.00 35.952015 . . . . . . . . . . 6.79 7.50 7.60 7.16 6.29 6.94 6.73 6.65 6.53 6.83 7.08 6.95 6.96 6.75 76.50 37.532016 . . . . . . . . . . 6.88 7.75 7.85 7.42 6.39 7.20 6.99 6.90 6.78 7.09 7.34 7.20 7.22 7.01 78.03 39.142017 . . . . . . . . . . 7.18 8.25 8.35 7.95 6.72 7.72 7.49 7.41 7.28 7.59 7.87 7.70 7.75 7.53 79.59 40.782018 . . . . . . . . . . 7.50 8.79 8.89 8.52 7.07 8.29 8.04 7.95 7.82 8.14 8.44 8.24 8.32 8.10 81.18 42.452019 . . . . . . . . . . 7.50 8.96 9.06 8.69 7.08 8.47 8.21 8.12 7.99 8.31 8.61 8.41 8.49 8.28 82.08 43.402020+ . . . . . . . . . 7.50 +2.0%/yr +2.0%/yr +2.0%/yr 7.08 +2.0%/yr +2.0%/yr+2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr+2.0%/yr +2.0%/yr +2.0%/yr

Notes:(1) Pricing assumptions provided by GLJ as used in the GLJ Tourmaline Reserve Report.(2) Inflation rates used for forecasting prices and costs.(3) Exchange rates used to generate the benchmark reference prices in this table.

AJM Exshaw Reserve Report Pricing AssumptionsSummary of Pricing and Inflation Rate Assumptions

Forecast Prices and Costs(1)

PriceInflationRate(2)

CostInflationRate(2)

Cdn to USExchangeRate(3)

Crude Oil PricingNatural Gas Liquids Pricing

Edmonton Par Prices

WTI atCushing

OklahomaUS$/Bbl

Real

WTI atCushing

OklahomaUS$/BblCurrent

EdmontonCity GateCdn$/Bbl

Real

EdmontonCity GateCdn$/BblCurrent

Med. Oil 29Deg. API

Cromer, SKCdn$/BblCurrent

Bow River25 Deg. APIHardistyCdn$/BblCurrent

Heavy Oil12 Deg. APIHardistyCdn$/BblCurrent

EthaneCdn$/BblCurrent

PropaneCdn$/BblCurrent

ButaneCdn$/BblCurrent

Pentanes +CondensateCdn$/BblCurrent

2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.0% 0.0% 0.950 75.00 75.00 77.55 77.55 65.05 60.55 58.85 16.50 42.65 62.05 81.452011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0% 2.0% 0.950 80.00 81.60 82.80 84.45 71.45 66.45 62.85 19.20 46.45 67.55 88.652012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0% 2.0% 0.950 82.50 85.85 85.45 88.90 75.40 69.90 64.20 20.25 48.90 71.10 93.352013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0% 2.0% 0.950 85.00 90.20 88.05 93.45 79.45 73.45 65.45 21.45 51.40 74.75 98.152014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0% 2.0% 0.950 90.00 97.40 93.35 101.05 86.05 79.05 68.05 21.73 55.60 80.85 106.102015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0% 2.0% 0.950 95.00 104.90 98.60 108.85 93.85 86.85 73.65 22.35 59.85 87.10 114.302016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 112.60 103.85 116.95 101.95 94.95 79.55 22.80 64.30 93.55 122.802017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 114.85 103.85 119.30 104.30 97.30 79.70 23.85 65.60 95.45 125.252018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 117.15 103.85 121.70 106.70 99.70 79.90 24.75 66.95 97.35 127.802019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 119.50 103.85 124.10 109.10 102.10 80.10 25.65 68.25 99.30 130.302020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 121.90 103.85 126.60 111.60 104.60 82.60 26.55 69.65 101.30 132.952021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 124.35 103.85 129.15 114.15 107.15 85.15 27.15 71.05 103.30 135.602022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 126.80 103.85 131.70 116.70 109.70 87.70 27.60 72.45 105.35 138.302023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 129.35 103.85 134.35 119.35 112.35 90.35 28.20 73.90 107.50 141.052024 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 131.95 103.85 137.05 122.05 115.05 93.05 28.80 75.40 109.65 143.902025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 134.60 103.85 139.80 124.80 117.80 95.80 29.40 76.90 111.85 146.802026 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 137.30 103.85 142.55 127.55 120.55 98.55 30.00 78.40 114.05 149.702027 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 140.00 103.85 145.40 130.40 123.40 101.40 30.60 79.95 116.30 152.652028 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 142.80 103.85 148.35 133.35 126.35 104.35 31.20 81.60 118.70 155.752029 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 145.70 103.85 151.30 136.30 129.30 107.30 31.95 83.20 121.05 158.852029+ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0% 2.0% 0.950 0.0% 2.0% 0.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0%

32

Natural Gas PricingSulphurPricing

AlbertaReferenceAveragePrice

Cdn$/McfCurrent

AlbertaAECOAveragePrice

Cdn$/McfReal


Cdn$/McfCurrent

AlbertaSystem PlantGate SalesCdn$/McfCurrent

AlbertaDirect PlantGate SalesCdn$/McfCurrent

B.C. DirectStn.2 SalesCdn$/McfCurrent

Sask. DirectPlant Gate

SalesCdn$/McfCurrent

NYMEXUS$/Mcf

Real

NYMEXUS$/McfCurrent

Alberta PlantGate Cdn$/lt

Current

2010 . . . . . . . . . . . . . . . . . . . . . . . 5.55 5.80 5.80 5.50 5.60 5.50 5.75 5.75 5.75 50.002011 . . . . . . . . . . . . . . . . . . . . . . . 6.45 6.60 6.70 6.40 6.50 6.40 6.65 6.50 6.65 50.002012 . . . . . . . . . . . . . . . . . . . . . . . 6.80 6.80 7.05 6.75 6.85 6.75 7.00 6.75 7.00 50.002013 . . . . . . . . . . . . . . . . . . . . . . . 7.15 7.00 7.45 7.15 7.25 7.15 7.40 6.90 7.30 50.002014 . . . . . . . . . . . . . . . . . . . . . . . 7.25 7.00 7.55 7.25 7.35 7.25 7.50 7.00 7.60 50.002015 . . . . . . . . . . . . . . . . . . . . . . . 7.45 7.00 7.75 7.45 7.55 7.45 7.70 7.20 7.95 51.002016 . . . . . . . . . . . . . . . . . . . . . . . 7.65 7.00 7.90 7.60 7.70 7.60 7.85 7.50 8.45 52.002017 . . . . . . . . . . . . . . . . . . . . . . . 8.00 7.20 8.25 7.95 8.05 7.95 8.20 7.65 8.80 53.052018 . . . . . . . . . . . . . . . . . . . . . . . 8.30 7.30 8.55 8.25 8.35 8.25 8.50 7.80 9.15 54.102019 . . . . . . . . . . . . . . . . . . . . . . . 8.60 7.40 8.85 8.55 8.65 8.55 8.80 7.90 9.45 55.202020 . . . . . . . . . . . . . . . . . . . . . . . 8.90 7.50 9.15 8.85 8.95 8.85 9.10 8.00 9.75 56.302021 . . . . . . . . . . . . . . . . . . . . . . . 9.05 7.50 9.35 9.05 9.15 9.05 9.30 8.00 9.95 57.452022 . . . . . . . . . . . . . . . . . . . . . . . 9.25 7.50 9.50 9.20 9.30 9.20 9.45 8.00 10.15 58.602023 . . . . . . . . . . . . . . . . . . . . . . . 9.45 7.50 9.70 9.40 9.50 9.40 9.65 8.00 10.35 59.752024 . . . . . . . . . . . . . . . . . . . . . . . 9.60 7.50 9.90 9.60 9.70 9.60 9.85 8.00 10.55 60.952025 . . . . . . . . . . . . . . . . . . . . . . . 9.85 7.50 10.10 9.80 9.90 9.80 10.05 8.00 10.75 62.152026 . . . . . . . . . . . . . . . . . . . . . . . 10.00 7.50 10.30 10.00 10.10 10.00 10.25 8.00 11.00 63.402027 . . . . . . . . . . . . . . . . . . . . . . . 10.25 7.50 10.50 10.20 10.30 10.20 10.45 8.00 11.20 64.652028 . . . . . . . . . . . . . . . . . . . . . . . 10.45 7.50 10.70 10.40 10.50 10.40 10.65 8.00 11.45 65.952029 . . . . . . . . . . . . . . . . . . . . . . . 10.65 7.50 10.95 10.65 10.75 10.65 10.90 8.00 11.65 67.252029+ . . . . . . . . . . . . . . . . . . . . . . 2.0% 0.0% 2.0% 2.0% 2.0% 2.0% 2.0% 0.0% 2.0% 2.0%

Notes:(1) Pricing assumptions provided by AJM as used in the AJM Exshaw Reserve Report.(2) Inflation rates used for forecasting prices and costs.(3) Exchange rates used to generate the benchmark reference prices in this table.

During the year ended December 31, 2009, Tourmaline and Exshaw (without reduction to reflect the 9.4%third-party minority interest in Exshaw), on a combined basis, received the following weighted average prices,excluding the gains and losses on financial instruments, in respect of its production: natural gas – $4.24/Mcf; NGL –$58.14/bbl; and oil – $71.36/bbl. The overall weighted average price received by Tourmaline on a combined oilequivalent basis was $29.28/Boe.

Additional Information Relating to Reserves Data

The additional information contained in this section pertains to Tourmaline and Exshaw on a consolidatedbasis and references to Tourmaline include Exshaw (without reduction to reflect the 9.4% third-party minorityinterest in Exshaw).

Undeveloped Reserves

The following tables set forth the proved undeveloped reserves and the probable undeveloped reserves, each byproduct type, attributed to Tourmaline’s properties as at the end of the financial year ended December 31, 2009.

Proved Undeveloped Reserves

Year

Light and Medium Crude Oil Natural Gas NGL Boe

(Mbbls) (MMcf) (Mbbls) (Mbbls)

2009(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 716 74,099 847 13,913

Note:(1) Tourmaline had no reserves prior to the financial year ended December 31, 2009.

In 2009, proved undeveloped reserves were primarily attributed to drilling locations distributed through the areas of theAlberta Deep Basin. It is anticipated that all of the proved undeveloped locations will be drilled by December 31, 2012.

Probable Undeveloped Reserves

Year

Light and Medium Crude Oil Natural Gas NGL Boe

(Mbbls) (MMcf) (Mbbls) (Mbbls)

2009(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,669 77,937 885 15,543

Note:(1) Tourmaline had no reserves prior to the financial year ended December 31, 2009.

33

In 2009, probable undeveloped reserves were primarily attributed to drilling locations distributed through theareas of the Alberta Deep Basin. It is anticipated that most of the future development capital associated with theprobable undeveloped reserves will be incurred by December 31, 2013.

In general, once proved and/or probable undeveloped reserves are identified, they are scheduled into Tourmaline’sdevelopment plans. Normally, Tourmaline plans to develop its proved and probable undeveloped reserves within twoyears. A number of factors that could result in delayed or cancelled development are as follows: changing economicconditions (due to pricing, operating and capital expenditure fluctuations); changing technical conditions (productionanomalies such as water breakthrough or accelerated depletion); multi-zone developments (delay of a prospectiveformation completion until the initial completion is no longer economic); a larger development program may need tobe spread out over several years to optimize capital allocation and facility utilization; and surface access issues(landowners, weather conditions and/or regulatory approvals). See “Risk Factors” and “Industry Conditions”.

Significant Factors or Uncertainties

The process of estimating reserves is complex. It requires significant judgments and decisions based on availablegeological, geophysical, engineering and economic data. These estimates may change substantially as additional datafrom ongoing development activities and production performance becomes available and as economic conditionsimpacting oil and gas prices and costs change. The reserves estimates contained in this prospectus are based on currentproduction forecasts, prices and economic conditions.

As circumstances change and additional data becomes available, reserve estimates also change. Estimates madeare reviewed and revised, either upward or downward, as warranted by the new information. Revisions are oftenrequired due to changes in well performance, prices, economic conditions and governmental restrictions.

Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is aninferential science. As a result, the subjective decisions, new geological or production information and a changingenvironment may impact these estimates. Revisions to reserve estimates can arise from changes in year-end oil andnatural gas prices and reservoir performance. Such revisions can be either positive or negative.

Other than as discussed above and the various risks and uncertainties that participants in the oil and natural gasindustry are exposed to generally, Tourmaline is unable to identify any important economic factors or significantuncertainties that will affect any particular components of the reserves data disclosed in this prospectus. See “RiskFactors” and “Industry Conditions”.

Future Development Costs

The following table sets forth development costs deducted in the estimation of Tourmaline’s future net revenueattributable to the reserve categories noted below ($000s):

Undiscounted Forecast Prices and Costs

YearProvedReserves

Proved PlusProbable Reserves

2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109,743 152,5722011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74,366 134,3142012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44,616 77,4092013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 25,4692014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — —2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — —Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 141 141

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 228,866 389,905

Tourmaline expects that the capital listed in the preceding table will be funded through its existing cash balance,expected cash flow from operations and completed financings.

34

Other Oil and Natural Gas Information

The additional information contained in this section pertains to Tourmaline and Exshaw on a consolidatedbasis and references to Tourmaline include Exshaw (without reduction to reflect the 9.4% third-party minorityinterest in Exshaw).

Crude Oil and Natural Gas Wells

The following table sets forth the number and status of wells in which Tourmaline had a working interest as atDecember 31, 2009, that Tourmaline considers capable of production.

Crude Oil Wells(1) Natural Gas Wells(1)

Producing Non-Producing(2) Producing Non-Producing(2)

Gross Net Gross Net Gross Net Gross Net

Alberta(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50.0 45.9 15.0 10.2 292.0 139.0 124.0 71.5British Columbia(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — — 5.0 2.8 6.0 4.1

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50.0 45.9 15.0 10.2 297.0 141.8 130.0 75.6

Notes:(1) All of Tourmaline’s wells are located onshore.(2) The non-producing oil wells and natural gas wells capable of production but which are not currently producing will be re-evaluated with respect

to future product prices, proximity to facility infrastructure, design of future exploration and development programs and access to capital.(3) Includes wells of Exshaw (without reduction to reflect the 9.4% third-party minority interest in Exshaw).

For a general description of Tourmaline’s important properties, facilities and installations, see “Description ofCore Long-Term Growth Areas”.

Properties with no Attributable Reserves

The following table sets out Tourmaline’s developed and undeveloped unproved properties as atDecember 31, 2009, in which Tourmaline has an interest.

Developed Acres Undeveloped Acres Total Acres

Gross Net Gross Net Gross Net

Alberta . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 219,000 109,000 426,000 266,000 645,000 375,000British Columbia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,000 5,000 8,000 5,000 16,000 10,000Saskatchewan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 74,000 66,000 74,000 66,000

Total(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 227,000 114,000 508,000 337,000 735,000 451,000

Note:(1) Includes developed and undeveloped unproved properties of Exshaw (without reduction to reflect the 9.4% third-party minority interest in

Exshaw).

The following table sets out Tourmaline’s developed and undeveloped unproved properties as at November8, 2010, in which Tourmaline has an interest.

Developed Acres Undeveloped Acres Total Acres

Gross Net Gross Net Gross Net

Alberta . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 257,000 147,000 872,000 681,000 1,129,000 828,000British Columbia . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22,000 11,000 131,000 56,000 153,000 67,000Saskatchewan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 74,000 66,000 74,000 66,000

Total(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 279,000 158,000 1,077,000 803,000 1,356,000 961,000

Note:(1) Includes developed and undeveloped unproved properties of Exshaw (without reduction to reflect the 9.4% third-party minority interest in

Exshaw).

There are no material work commitments in respect of Tourmaline’s unproved properties. Tourmaline expects thatrights to explore, develop and/or exploit 4,250 net acres (seven net sections) of its undeveloped land holdings willexpire by December 31, 2010.

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Additional Information Concerning Abandonment and Reclamation Costs

Tourmaline uses its internal historical costs to estimate its abandonment and reclamation costs when available.The costs are estimated on an area-by-area basis. The industry’s historical costs are used when available. Ifrepresentative comparisons are not readily available, an estimate is prepared based on the various regulatoryabandonment requirements. As at December 31, 2009, Tourmaline had 273.5 net wells for which it expects toeventually incur abandonment and reclamation costs by 2026.

The total abandonment and reclamation costs in respect of proved and probable reserves using forecast prices are$26.75 million (undiscounted) and $5.67 million (discounted at 10%). One hundred percent of such amounts werededucted as abandonment and reclamation costs in estimating Tourmaline’s future net revenue in respect of proved andprobable reserves as disclosed above.

The following table sets forth abandonment and reclamation costs deducted in the estimation of Tourmaline’sfuture net revenue:

Forecast Prices and Costs (Total Proved plus Probable) ($000s)

Year

Abandonment andReclamation Costs(Undiscounted)

Abandonment andReclamation Costs

(Discounted at 10%)

2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 242011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 220 1822012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 382 287Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26,121 5,180

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26,750 5,673

Tourmaline expects to pay approximately $1.5 million in the next three financial years in respect of itsabandonment and reclamation costs.

Tax Horizon

Tourmaline has no current tax expense and, based on current reserve forecasts, will be able to realize the benefitof the majority of the non-capital losses and expects to remain non-taxable through at least 2011. Tourmaline hasestimated approximately $1,182 million of tax pools will be available as at December 31, 2010, which can be used tooffset taxable income in future years.

Capital Expenditures

The following table summarizes capital expenditures (including corporate acquisitions and capitalized generaladministrative expenses) related to Tourmaline’s activities for the year ended December 31, 2009:

$000’s

Exploration, drilling and completions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 110,427Development, equipping and facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,472Property and corporate acquisitions(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 351,841Equipment and facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20,781Geological and geophysical . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,012Other (including capitalized G&A) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,725

Total(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 499,258

Notes:(1) Approximately $266.1 million of the property acquisition expenditures were for proved properties and approximately $94.4 million of the

property acquisition expenditures were for unproved properties.(2) Includes capital expenditures related to Exshaw (without reduction to reflect the 9.4% third-party minority interest in Exshaw).

36

Exploration and Development Activities

The following table sets forth the gross and net exploratory and development wells in which Tourmalineparticipated in the year ended December 31, 2009:

Exploratory Wells Development Wells

Gross Net Gross Net

Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21.0 19.2 9.0 5.9Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — —Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — —Dry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — —

Total(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21.0 19.2 9.0 5.9

Note:(1) Includes wells in which Exshaw participated (without reduction to reflect the 9.4% third-party minority interest in Exshaw).

See “Description of Core Long-Term Growth Areas” and “Description of the Business” for a description ofTourmaline’s exploration and development plans.

Production Estimates

The following table sets out the volume of Tourmaline’s production estimated for the year ended December 31,2010 as evaluated by GLJ, which is reflected in the estimate of future net revenue disclosed in the tables containedunder “Disclosure of Reserves Data” above.

Light and Medium Crude Oil Natural Gas NGL Total

Reserves CategoryGross(Boe/d)

Net(Boe/d)

Gross(Mcf/d)

Net(Mcf/d)

Gross(Boe/d)

Net(Boe/d)

Gross(Boe/d)

Net(Boe/d)

PROVEDAnsel . . . . . . . . . . . . . . . . . . . . . — — 3,438 3,206 43 37 616 571Harley . . . . . . . . . . . . . . . . . . . . — — 14,793 13,101 211 156 2,677 2,339Hinton . . . . . . . . . . . . . . . . . . . . — — 7,686 6,278 — — 1,281 1,046Kakwa . . . . . . . . . . . . . . . . . . . . 15 12 5,875 5,120 102 77 1,097 942Wild River . . . . . . . . . . . . . . . . . — — 12,244 11,512 155 111 2,195 2,030Spirit River . . . . . . . . . . . . . . . . 901 744 8,194 6,025 65 42 2,332 1,789Other Properties . . . . . . . . . . . . 177 122 11,645 10,008 121 89 2,238 1,879

Total Proved . . . . . . . . . . . . . . 1,093 878 63,875 55,249 697 512 12,435 10,596

PROVED PLUS PROBABLEAnsel . . . . . . . . . . . . . . . . . . . . . — — 3,801 3,550 48 41 681 633Harley . . . . . . . . . . . . . . . . . . . . — — 18,211 16,137 260 198 3,295 2,888Hinton . . . . . . . . . . . . . . . . . . . . — — 9,041 7,337 — — 1,507 1,223Kakwa . . . . . . . . . . . . . . . . . . . . 15 12 7,189 6,260 125 96 1,339 1,151Wild River . . . . . . . . . . . . . . . . . — — 12,628 11,848 160 115 2,264 2,090Spirit River . . . . . . . . . . . . . . . . 976 810 8,726 6,436 70 45 2,500 1,928Other Properties . . . . . . . . . . . . 197 141 15,160 13,208 153 117 2,877 2,459

Total Proved PlusProbable . . . . . . . . . . . . . . . . 1,188 963 74,756 64,777 816 613 14,463 12,372

Notes:(1) The properties in this table are the only properties which accounted for 5% or more of Tourmaline’s estimated 2010 production in the GLJ

Tourmaline Reserve Report and the AJM Exshaw Reserve Report.(2) Numbers may not add due to rounding.(3) Includes Exshaw production (without reduction to reflect the 9.4% third-party minority interest in Exshaw).

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Production History

The following tables summarize certain information in respect of average production, product prices received,royalties paid, operating expenses and resulting netback for the periods indicated below:

Quarter Ended

2009(4)

Dec. 31 Sept. 30 June 30 Mar. 31

Average Daily Production(1)

Light and Medium Crude Oil (Bbls/d) . . . . . . . . . . . . . . . . . . . . . 621 130 20 10Natural Gas (Mcf/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37,554 22,478 12,747 1,867NGL (Bbls/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 368 100 46 3Combined (Boe/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,248 3,976 2,191 324

Average Price ReceivedLight and Medium Crude Oil ($/bbl) . . . . . . . . . . . . . . . . . . . . . . 71.35 72.86 72.31 50.37Natural Gas ($/Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.08 3.05 3.76 4.86NGL ($/bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62.39 46.15 52.22 26.60Combined ($/Boe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35.59 20.80 23.66 29.79

Royalties PaidLight and Medium Crude Oil ($/bbl) . . . . . . . . . . . . . . . . . . . . . . 15.52 26.05 20.30 8.60Natural Gas ($/Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.14 0.43 0.71 1.25NGL ($/bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23.01 28.37 18.21 —Combined ($/Boe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.24 3.99 4.72 7.45

Production Costs (includes transportation)Light and Medium Crude Oil ($/bbl) . . . . . . . . . . . . . . . . . . . . . . 30.38 14.29 22.70 —Natural Gas ($/Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.48 1.20 0.66 1.51NGL ($/bbl)(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — —Combined ($/Boe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.63 6.85 3.95 8.69

Netback Received ($/Boe)(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22.72 9.91 14.98 13.63

Notes:(1) Before deduction of royalties.(2) NGL volumes are derived from natural gas production, as such all the related operating costs are attributed to the production of natural gas.(3) Netbacks are calculated by subtracting royalties and operating costs from revenues.(4) Includes Exshaw (without reduction to reflect the 9.4% third-party minority interest in Exshaw).

The following table sets forth the average daily production volumes for the year ended December 31, 2009 foreach of the important fields comprising Tourmaline’s assets.

Light andMedium Crude

Oil (Bbls/d)Natural Gas

(Mcf/d)NGL

(Bbls/d)Boe

(Boe/d)

Alberta Deep Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75 16,705 120 2,979Other Alberta properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117 1,713 10 412British Columbia properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 352 — 64

Total(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 197 18,770 130 3,455

Note:(1) Includes Exshaw (without reduction to reflect the 9.4% third-party minority interest in Exshaw).

For the year ended December 31, 2009, approximately 79% of Tourmaline’s gross revenue was derived fromnatural gas production and approximately 21% was derived from crude oil and NGL production.

Forward Contracts and Marketing

Other than the following, Tourmaline is not bound by any agreement (including any transportation agreement),directly or through an aggregator, under which it is precluded from fully realizing, or may be protected from the fulleffect of, future market prices for crude oil or natural gas.

38

The Company’s commodity hedging policy has been established with the Board of Directors authorizingmanagement to hedge up to 50% of current production. For the third quarter of 2010, Tourmaline produced 103.3MMcf/d. In the fourth quarter of 2010, an average of 23.3 (23%) MMcf/d is sold forward at an average fixed price of$6.02 per Mcf. In a similar manner, an average of 24.4 (24%) MMcf/d is sold forward at an average fixed price of$6.01 per Mcf for 2011.

Forward sales of crude oil at fixed prices constitute less than 15% of the Company’s third quarter 2010 oil andNGL production.

In addition, Tourmaline’s transportation obligations or commitments for future physical deliveries of crude oil andnatural gas do not exceed Tourmaline’s expected related future production from its proved reserves, estimated usingforecast prices and costs, as disclosed in this prospectus.

2010 Acquired Reserves

The following tables disclose the estimated reserves and related future net revenue attributable to reservesacquired by Tourmaline in 2010 pursuant to the Altia Acquisition and the Greater Hinton Acquisition, as well as thepricing assumptions used to develop these estimates and the estimated crude oil, NGL and natural gas productionvolumes for each acquisition for the first year reflected in these estimates. The estimates of future net revenuedisclosed do not represent fair market value. The estimates of crude oil, natural gas and NGL reserves provided hereinare estimates only. Actual crude oil, natural gas and NGL reserves may be greater or less than the estimates providedherein.

Altia Reserves as at March 31, 2009

The reserves data set forth below is based upon the Sproule Altia Reserve Report. The Sproule Altia ReserveReport evaluates the crude oil, NGL and natural gas reserves of Altia which were acquired by Tourmaline pursuant tothe Altia Acquisition and the net present values of future net revenue for these reserves using forecast prices and costs.The Sproule Altia Reserve Report has been prepared in accordance with the standards contained in the COGEHandbook and the reserve definitions contained in NI 51-101 and the COGE Handbook.

The information relating to the crude oil, NGL and natural gas reserves of Altia contains forward-lookingstatements relating to future net revenues and anticipated production. See “Forward-Looking Statements”, “CertainReserves Data Information”, “Industry Conditions” and “Risk Factors – Reserves Estimates”.



Reserves Category

CompanyGross

(Mbbls)


CompanyGross

(MMcf)


CompanyGross

(Mbbls)


Proved Developed Producing . . . . . . . . . . . . . . . 4.8 4.6 5,624 4,256 7.9 5.0Proved Developed Non-Producing . . . . . . . . . . . — — 628 466 29.6 23.7Proved Undeveloped . . . . . . . . . . . . . . . . . . . . . . 10.9 10.6 4,809 3,556 223.5 178.8

Total Proved Reserves . . . . . . . . . . . . . . . . . . . . . 15.8 15.2 11,061 8,277 261.0 207.4Total Probable Reserves . . . . . . . . . . . . . . . . . . . 12.5 11.6 5,510 4,194 123.7 98.2

Total Proved Plus Probable Reserves 28.3 26.7 16,571 12,471 384.6 305.7

39




Reserves Category0

(M$)5

(M$)10

(M$)15

(M$)20

(M$)10%/yr($/Boe)

Proved Developed Producing . . . . . . . . . . . . . . . . . . . . 19,653 18,006 16,668 15,558 14,623 23.19Proved Developed Non-Producing . . . . . . . . . . . . . . . . 2,895 2,440 2,083 1,798 1,566 20.56Proved Undeveloped . . . . . . . . . . . . . . . . . . . . . . . . . . . 19,663 12,228 7,801 4,955 3,021 9.98

Total Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . 42,211 32,674 26,552 22,311 19,210 16.57Total Probable Reserves . . . . . . . . . . . . . . . . . . . . . . . . 31,245 18,520 13,057 10,044 8,112 16.14

Total Proved Plus Probable Reserves . . . . . . . . . . . . 73,456 51,194 39,608 32,355 27,322 16.43

Sproule Altia Reserve Report Pricing Assumptions

Summary of Pricing and Inflation Rate AssumptionsForecast Prices and Costs

YearWTI CushingOklahoma

Edmonton ParPrice

40° API

AlbertaAECO-C

Spot Henry Hub

Forecast $US/Bbl $Cdn/Bbl $Cdn/MMBtu $US/MMBtu

2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49.10 59.56 4.70 4.602010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55.42 63.37 5.93 5.932011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60.37 67.15 6.42 6.542012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75.37 77.48 7.12 7.762013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81.18 83.58 7.50 8.122014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82.81 85.27 7.67 8.282015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84.46 86.99 7.84 8.452016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86.15 88.75 8.02 8.622017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87.87 90.55 8.20 8.792018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89.63 92.38 8.38 8.962019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91.42 94.25 8.57 9.14Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . +2% per year +2% per year +2% per year +2% per year

Notes:(1) Inflation rates used for forecasting prices and costs.(2) Exchange rates used to generate the benchmark reference prices in this table.(3) Pricing assumptions provided by Sproule as used in the Sproule Altia Reserve Report.

Altia Acquisition 2010 Production Estimates

Light and MediumCrude Oil Natural Gas NGL Total

Reserves Category

CompanyGross(Boe/d)

CompanyNet ofRoyalty(Boe/d)

CompanyGross(Mcf/d)

CompanyNet ofRoyalty(Mcf/d)

CompanyGross(Boe/d)


CompanyGross(Boe/d)


Total Proved Reserves . . . . . . . . 6 5 5,680 4,421 77 60 1,030 802Total Probable Reserves . . . . . . . 1 — 1,563 1,216 8 6 269 209

Total Proved Plus ProbableReserves . . . . . . . . . . . . . . . . . 7 5 7,243 5,637 85 66 1,299 1,011

40

Greater Hinton Reserves as at November 30, 2009

The reserves data set forth below is based upon the AJM Greater Hinton Reserve Report. The AJM GreaterHinton Reserve Report evaluates the crude oil, NGL and natural gas reserves of the assets acquired by Tourmalinepursuant to the Greater Hinton Acquisition and the net present values of future net revenue for these reserves usingforecast prices and costs. The AJM Greater Hinton Reserve Report has been prepared in accordance with the standardscontained in the COGE Handbook and the reserve definitions contained in NI 51-101 and the COGE Handbook.

The information relating to the crude oil, NGL and natural gas reserves of the assets acquired by Tourmalinepursuant to the Greater Hinton Acquisition contains forward-looking statements relating to future net revenues andanticipated production. See “Forward-Looking Statements”, “Certain Reserves Data Information”, “IndustryConditions” and “Risk Factors – Reserves Estimates”.


Reserves Category

Light and MediumCrude Oil Natural Gas NGL

CompanyGross

(Mbbls)


CompanyGross

(MMcf)


CompanyGross

(Mbbls)


Proved Developed Producing . . . . . . . . . . . . . . . . . . . . 18 14 55,797 47,193 32 22Proved Developed Non-Producing . . . . . . . . . . . . . . . . — — 3,229 2,881 11 8Proved Undeveloped . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 57,251 49,276 67 50

Total Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . 18 14 116,278 99,350 110 81Total Probable Reserves . . . . . . . . . . . . . . . . . . . . . . . . 7 5 86,470 69,842 82 56

Total Proved Plus Probable Reserves . . . . . . . . . . . . 25 19 202,748 169,192 192 137




Reserves Category0

(M$)5

(M$)10

(M$)15

(M$)20

(M$)10%/yr($/Boe)

Proved Developed Producing . . . . . . . . . . . . . . 310,084 208,417 158,216 129,043 110,108 20.02Proved Developed Non-Producing . . . . . . . . . . 16,043 10,840 8,189 6,596 5,532 16.78Proved Undeveloped . . . . . . . . . . . . . . . . . . . . 230,000 115,641 61,283 30,900 11,893 7.42

Total Proved Reserves . . . . . . . . . . . . . . . . . . . 556,128 334,898 227,688 166,539 127,532 13.67Total Probable Reserves . . . . . . . . . . . . . . . . . . 549,673 192,093 83,979 40,050 18,283 7.18

Total Proved Plus Probable Reserves . . . . . . 1,105,801 526,991 311,667 206,589 145,815 10.99

41

AJM Greater Hinton Reserve Report Pricing Assumptions

Summary of Pricing and Inflation Rate AssumptionsForecast Prices and Costs

Crude Oil PricingNatural Gas Liquids Pricing

Edmonton Par Prices

PriceInflationRate1

CostInflationRate1

Cdn to USExchange

Rate2

WTI atCushing

OklahomaUS$/Bbl Real

WTI atCushing

OklahomaUS$/BblCurrent

EdmontonCity GateCdn$/Bbl

Real

EdmontonCity GateCdn$/BblCurrent

Med. Oil 29Deg. API

Cromer, SKCdn$/BblCurrent

Bow River25 Deg. APIHardistyCdn$/BblCurrent

Heavy Oil12 Deg. APIHardistyCdn$/BblCurrent

EthaneCdn$/BblCurrent

PropaneCdn$/BblCurrent

ButaneCdn$/BblCurrent

Pentanes +CondensateCdn$/BblCurrent

2009 . . . . . . . . . . . . . . 0.0% 0.0% 0.920 65.00 65.00 70.00 70.00 59.00 55.00 53.50 12.60 42.00 56.00 73.502010 . . . . . . . . . . . . . . 2.0% 2.0% 0.950 70.00 71.40 72.50 73.95 62.45 57.95 54.75 17.40 44.35 59.15 77.652011 . . . . . . . . . . . . . . 2.0% 2.0% 0.950 75.00 78.05 77.50 80.60 67.60 62.60 57.20 20.70 48.35 64.50 84.652012 . . . . . . . . . . . . . . 2.0% 2.0% 0.950 80.00 84.90 83.00 88.10 74.60 69.10 61.50 21.45 52.85 70.50 92.502013 . . . . . . . . . . . . . . 2.0% 2.0% 0.950 85.00 92.00 88.00 95.25 80.75 74.25 63.75 21.90 57.15 76.20 100.002014 . . . . . . . . . . . . . . 2.0% 2.0% 0.950 90.00 99.35 93.00 102.70 87.70 80.70 67.50 22.35 61.60 82.15 107.852015 . . . . . . . . . . . . . . 2.0% 2.0% 0.950 95.00 107.00 98.50 110.95 95.95 88.95 73.55 22.80 66.55 88.75 116.502016 . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 114.85 103.50 118.90 103.90 96.90 79.30 23.25 71.35 95.10 124.852017 . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 117.15 103.50 121.25 106.25 99.25 79.45 24.45 72.75 97.00 127.302018 . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 119.50 103.50 123.70 108.70 101.70 79.70 25.20 74.20 98.95 129.902019 . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 121.90 103.50 126.15 111.15 104.15 82.15 26.10 75.70 100.90 132.452020 . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 124.35 103.50 128.70 113.70 106.70 84.70 27.15 77.20 102.95 135.152021 . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 126.80 103.50 131.25 116.25 109.25 87.25 27.60 78.75 105.00 137.802022 . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 129.35 103.50 133.90 118.90 111.90 89.90 28.20 80.35 107.10 140.602023 . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 131.95 103.50 136.55 121.55 114.55 92.55 28.80 81.95 109.25 143.402024 . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 134.60 103.50 139.30 124.30 117.30 95.30 29.40 83.60 111.45 146.252025 . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 137.30 103.50 142.10 127.10 120.10 98.10 30.00 85.25 113.70 149.202026 . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 140.00 103.50 144.95 129.95 122.95 100.95 30.60 86.95 115.95 152.202027 . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 142.80 103.50 147.85 132.85 125.85 103.85 31.20 88.70 118.30 155.252028 . . . . . . . . . . . . . . 2.0% 2.0% 0.950 100.00 145.70 103.50 150.80 135.80 128.80 106.80 31.95 90.50 120.65 158.352029 . . . . . . . . . . . . . . 2.0% 2.0% 0.950 0.0% 2.0% 0.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0%

Natural Gas Pricing Sulphur Pricing

AlbertaReferenceAveragePrice

Cdn$/McfCurrent


Cdn$/McfReal


Cdn$/McfCurrent

AlbertaSystem PlantGate SalesCdn$/McfCurrent

AlbertaDirect PlantGate SalesCdn$/McfCurrent

B.C. DirectStn.2 SalesCdn$/McfCurrent

Sask. DirectPlant Gate

SalesCdn$/McfCurrent

NYMEXUS$/Mcf

Real

NYMEXUS$/McfCurrent

Alberta PlantGate Cdn$/lt

Current

2009 . . . . 4.25 4.50 4.50 4.20 4.30 4.20 4.45 4.50 4.50 50.002010 . . . . 5.85 6.00 6.10 5.80 5.90 5.80 6.05 6.00 6.10 50.002011 . . . . 6.90 6.90 7.20 6.90 7.00 6.90 7.15 6.85 7.10 50.002012 . . . . 7.15 7.00 7.45 7.15 7.25 7.15 7.40 7.00 7.40 50.002013 . . . . 7.30 7.00 7.60 7.30 7.40 7.30 7.55 7.20 7.80 50.002014 . . . . 7.45 7.00 7.75 7.45 7.55 7.45 7.70 7.30 8.10 51.002015 . . . . 7.65 7.00 7.90 7.60 7.70 7.60 7.85 7.40 8.30 52.002016 . . . . 7.80 7.00 8.05 7.75 7.85 7.75 8.00 7.50 8.60 53.052017 . . . . 8.15 7.20 8.45 8.15 8.25 8.15 8.40 7.65 9.00 54.102018 . . . . 8.45 7.30 8.70 8.40 8.50 8.40 8.65 7.80 9.30 55.202019 . . . . 8.75 7.40 9.00 8.70 8.80 8.70 8.95 7.90 9.60 56.302020 . . . . 9.05 7.50 9.35 9.05 9.15 9.05 9.30 8.00 9.95 57.452021 . . . . 9.25 7.50 9.50 9.20 9.30 9.20 9.45 8.00 10.15 58.602022 . . . . 9.45 7.50 9.70 9.40 9.50 9.40 9.65 8.00 10.35 59.752023 . . . . 9.60 7.50 9.90 9.60 9.70 9.60 9.85 8.00 10.55 60.952024 . . . . 9.85 7.50 10.10 9.80 9.90 9.80 10.05 8.00 10.75 62.152025 . . . . 10.00 7.50 10.30 10.00 10.10 10.00 10.25 8.00 11.00 63.402026 . . . . 10.25 7.50 10.50 10.20 10.30 10.20 10.45 8.00 11.20 64.652027 . . . . 10.45 7.50 10.70 10.40 10.50 10.40 10.65 8.00 11.45 65.952028 . . . . 10.65 7.50 10.95 10.65 10.75 10.65 10.90 8.00 11.65 67.252029 . . . . 2.0% 0.0% 2.0% 2.0% 2.0% 2.0% 2.0% 0.0% 2.0% 2.0%

42

Notes:(1) Inflation rates used for forecasting prices and costs.(2) Exchange rates used to generate the benchmark reference prices in this table.(3) Pricing assumptions provided by AJM as used in the AJM Greater Hinton Reserve Report.

Greater Hinton Acquisition 2010 Production Estimates

Light and MediumCrude Oil Natural Gas NGL Total

Reserves Category

CompanyGross(Boe/d)


CompanyGross(Mcf/d)

CompanyNet ofRoyalty(Mcf/d)

CompanyGross(Boe/d)


CompanyGross(Boe/d)


Total Proved Reserves . . . . . . . . 18.6 16.8 43,651 39,504 39.5 35.8 7,333 6,637Total Probable Reserves . . . . . . . 1.9 1.7 143 100 0.9 0.8 27 19

Total Proved Plus ProbableReserves . . . . . . . . . . . . . . . . . 20.5 18.5 43,794 39,604 40.4 36.6 7,360 6,656

OTHER BUSINESS INFORMATION

Specialized Skill and Knowledge

Tourmaline employs individuals with various professional skills in the course of pursuing its business plan. Theseprofessional skills include, but are not limited to, geology, geophysics, engineering, financial and business skills, whichare widely available in the industry. Drawing on significant experience in the oil and gas business, Tourmaline believesits management team has a demonstrated track record of bringing together all of the key components to a successfulexploration and production company: strong technical skills; expertise in planning and financial controls; ability toexecute on business development opportunities; capital markets expertise; and an entrepreneurial spirit that allowsTourmaline to effectively identify, evaluate and execute on value added initiatives.

Competitive Conditions

The oil and natural gas industry is very competitive. The Canadian Association of Petroleum Producers estimatesthat there are over 1,000 exploration and production companies in Canada. Tourmaline controls less than one percentof the business in western Canada, but where it is active (see “Description of Core Long-Term Growth Areas”),Tourmaline believes it has a strong competitive position.

Companies operating in the petroleum industry must manage risks which are beyond the direct control ofcompany personnel. Among these risks are those associated with exploration, environmental damage, commodityprices, foreign exchange rates and interest rates.

The oil and natural gas industry is intensely competitive and Tourmaline competes with a substantial number ofother entities, many of which have greater technical or financial resources. With the maturing nature of the WCSB, theaccess to new prospects is becoming more competitive and complex.

Tourmaline attempts to enhance its competitive position by operating in areas where it believes its technicalpersonnel are able to reduce some of the risks associated with exploration, production and marketing because they arefamiliar with the areas of operation. Management believes that Tourmaline will be able to explore for and develop newproduction and reserves with the objective of increasing its cash flow and reserve base. See “Risk Factors –Competition”.

Cycles

The Company’s business is generally not cyclical. The exploration for and the development of oil and natural gasreserves is dependent on access to areas where drilling is to be conducted. Seasonal weather variation, including“freeze-up” and “break-up”, affect access in certain circumstances. See “Risk Factors – Seasonality”.

43

Environmental Protection

The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety ofprovincial and federal legislation. Compliance with such legislation may require significant expenditures or result inoperational restrictions. Breach of such requirements may result in suspension or revocation of necessary licenses andauthorizations, civil liability for pollution damage and the imposition of material fines and penalties, all of which mighthave a significant negative impact on earnings and overall competitiveness of the Company. For a description of thefinancial and operational effects of environmental protection requirements on the capital expenditures, earnings andcompetitive position of Tourmaline see “Industry Conditions – Environmental Regulation” and “Risk Factors –Environmental”.

Employees

At December 31, 2009, Tourmaline had 47 full time employees and four consultants located at its Calgary office,and seven full time employees and 16 contract operators in various field locations. Tourmaline currently has 69 fulltime employees and seven consultants located at its Calgary office, and 14 full time employees and 32 contractoperators in various field locations. Management believes that Tourmaline currently has sufficient staff to operate up toapproximately 30,000 Boe/d of production with minimal staff additions.

Reorganizations

Other than disclosed under “Description of the Business – Three-Year History”, Tourmaline has not completedany material reorganization within the three most recently completed financial years or completed during the currentfinancial year. No material reorganization is currently proposed for the current financial year. See “Description of theBusiness – Three-Year History”.

Environmental, Health and Safety Policies

The Company supports environmental protection and employee health and safety by integrating the essentialprinciples and practices through its environmental management systems and employee occupational health and safetyprograms. The Company promotes safety and environmental awareness and protection through the implementation andcommunication of the Company’s environmental management and employee occupational health and safety programspolicies and procedures. Committee structures are established in the Company’s operations which are designed toallow for employee participation and development of policies and programs which provide employees with joborientation, training, instruction and supervision to assist them in conducting their activities in an environmentallyresponsible and safe manner.

The Company develops emergency response teams and preparedness plans in conjunction with local authorities,emergency services and the communities in which it operates in order to effectively respond to an environmentalincident should it arise. Environmental assessments are undertaken for new projects or when acquiring new propertiesor facilities in order to identify, assess and minimize environmental risks and operational exposures. The Companyconducts audits of operations to confirm compliance with internal standards and to stimulate improvement in practiceswhere needed. Documentation is maintained to support internal accountability and measure operational performanceagainst recognized industry indicators to assist in achieving the objectives of the described policies and programs.

The Company also faces environmental, health and safety risks in the normal course of its operations due to thehandling and storage of hazardous substances. The Company’s environmental and occupational health and safetymanagement systems are designed to manage such risks in the Company’s business and allow action to be taken tomitigate the extent of any environmental, health or safety impacts from such operations. A key aspect of these systemsis the performance of annual environmental and occupational health and safety audits.

44

SELECTED HISTORICAL AND PRO FORMACONSOLIDATED FINANCIAL AND OPERATIONAL INFORMATION

Selected Historical Consolidated Financial and Operational Information

The following table sets out selected consolidated historical financial and operational information as at and for theperiods indicated.

The selected historical consolidated financial information set out below as at December 31, 2009 and 2008, and forthe year ended December 31, 2009 and the period from incorporation on July 21, 2008 to December 31, 2008, has beenderived from the Company’s audited consolidated financial statements and related notes appearing elsewhere in thisprospectus. The Company’s audited consolidated financial statements appearing elsewhere in this prospectus have beenaudited by the Company’s auditors, KPMG LLP. KPMG LLP’s auditor’s report on these consolidated financialstatements is included elsewhere in this prospectus. The selected historical consolidated financial information set outbelow as at September 30, 2010 and 2009 and for the nine months ended September 30, 2010 and 2009 has been derivedfrom the Company’s unaudited interim consolidated financial statements included elsewhere in this prospectus. Theunaudited consolidated financial information presented has been prepared on a basis consistent with the Company’saudited consolidated financial statements. Investors should read the selected historical consolidated financial informationin conjunction with “Management’s Discussion and Analysis” and the Company’s audited and unaudited consolidatedfinancial statements and the accompanying notes, which financial statements are included elsewhere in this prospectus.

As at and for the nine months endedAs at and forthe year ended

December 31, 2009

As at and for the periodfrom incorporation on

July 21, 2008 toDecember 31, 2008September 30, 2010 September 30, 2009

ProductionNatural gas (Mcf) . . . . . . . . 23,644,856 3,396,003 6,850,937 —Crude oil and NGL

(Bbls) . . . . . . . . . . . . . . . 464,852 28,369 119,347 —Oil equivalent (Boe) . . . . . 4,405,661 594,370 1,261,170 —Natural gas (Mcf/d) . . . . . . 86,611 12,440 18,770 —Crude oil and NGL

(Bbls/d) . . . . . . . . . . . . . 1,703 104 327 —Oil equivalent (Boe/d) . . . . 16,138 2,177 3,455 —

Financial ($000s, unlessotherwise noted)Revenue, net of

royalties . . . . . . . . . . . . . 153,615 12,644 35,127 1,237Cash flow from

operations . . . . . . . . . . . 97,999 8,874 (514) 522Funds from operations(1) . . 89,651 7,154 21,722 802Per diluted share . . . . . . . . 0.74 0.13 0.31 0.04Net earnings (loss) . . . . . . . 17,145 (1,752) (2,121) 438Per basic share . . . . . . . . . . 0.15 (0.03) (0.03) 0.02Per diluted share . . . . . . . . 0.14 (0.03) (0.03) 0.02Total assets . . . . . . . . . . . . 1,540,236 561,339 1,003,882 321,779Working capital . . . . . . . . . (65,154) 84,622 161,514 314,743Working capital (adjusted

for the fair value offinancial instruments andfuture taxes)(1) . . . . . . . . (78,314) 84,622 161,190 314,743

Long-term financialliabilities . . . . . . . . . . . . 56,706 — — —

Capital Expenditures . . . . . 598,082 373,312 499,258 3,575Basic outstanding shares

(000s) . . . . . . . . . . . . . . . 123,841 73,553 101,809 53,000

Per UnitNatural gas ($/Mcf) . . . . . . 4.69 3.38 4.24 —Crude oil and NGL

($/Bbl) . . . . . . . . . . . . . . 73.57 59.95 66.10 —Revenue ($/Boe) . . . . . . . . 32.95 22.20 29.28 —Operating and

transportation costs($/Boe) . . . . . . . . . . . . . . 8.46 5.97 7.91 —

Operating netback(1)

($/Boe) . . . . . . . . . . . . . . 21.31 11.82 17.58 —

Notes:(1) See “GAAP and Non-GAAP Financial Measures” and “Management’s Discussion and Analysis – Non-GAAP Financial Measures”.(2) Certain amounts have been restated for purchase price adjustments relating to property acquisitions that occurred in prior periods.

45

Selected Pro Forma Consolidated Financial and Operational Information

The following table sets out selected unaudited pro forma consolidated financial and operational information as atand for the periods indicated after giving effect to the Tourmaline Significant Acquisitions and the completion of theOffering and the Concurrent Private Placement.

The selected unaudited pro forma consolidated financial information set out below has been derived from theCompany’s unaudited pro forma consolidated financial statements and accompanying notes included elsewhere in thisprospectus. Investors should read the selected pro forma consolidated financial information in conjunction with theCompany’s unaudited pro forma consolidated financial statements and the consolidated financial statements andaccompanying notes of the Company from which the unaudited pro forma consolidated financial statements arederived, which financial statements are included elsewhere in this prospectus. The Company’s unaudited pro formaconsolidated financial statements have been prepared by management of Tourmaline in accordance with CanadianGAAP. In the opinion of management, the unaudited pro forma consolidated financial statements include alladjustments necessary for fair presentation in accordance with Canadian GAAP. The unaudited pro forma consolidatedfinancial statements are not necessarily indicative of either the financial position or results of operations that actuallywould have occurred if the events reflected therein had been in effect on the dates indicated or of the results that maybe obtained in the future. The unaudited pro forma consolidated financial statements do not contemplate future changesin accounting policies due to the adoption of IFRS.

Unaudited pro forma as atand for the nine months

ended September 30, 2010

Unaudited pro formafor the

year ended December 31, 2009

ProductionNatural gas (Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27,696,960 27,781,676Crude oil and NGL (Bbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 477,071 510,359Oil equivalent (Boe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,093,231 5,140,639Gas (Mcf/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101,454 76,114Crude oil and NGL (Bbls/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,748 1,398Oil equivalent (Boe/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18,657 14,084

Financial ($000s, unless otherwise noted)Revenue, net of royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 169,755 125,773Funds from operations(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104,062 77,137Per diluted share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.78 0.73Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17,349 (13,132)Per basic share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.13 (0.13)Per diluted share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.13 (0.13)Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,711,600 (3)

Working capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106,210 (3)

Working capital (adjusted for the fair value of financialinstruments and future taxes)(1) . . . . . . . . . . . . . . . . . . . . . . . 93,050 (3)

Basic outstanding shares (000s) . . . . . . . . . . . . . . . . . . . . . . . . . 134,691 121,571

Per Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Natural gas ($/Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.66 4.16Crude oil and NGL ($/Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73.56 54.73Revenue ($/Boe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32.23 27.93Operating and transportation costs ($/Boe) . . . . . . . . . . . . . . . . 7.67 7.28Operating netback(1) ($/Boe) . . . . . . . . . . . . . . . . . . . . . . . . . . . 21.26 16.57

Notes:(1) See “GAAP and Non-GAAP Financial Measures” and “Management’s Discussion and Analysis – Non-GAAP Financial Measures”.(2) Certain amounts have been restated for purchase price adjustments relating to property acquisitions that occurred in prior periods.(3) A pro forma balance sheet as at December 31, 2009 has not been prepared.(4) The underlying assumptions for the pro forma adjustments provide a reasonable basis for presenting the significant financial effects directly

attributable to the transactions discussed herein, however, the pro forma consolidated financial statements are not necessarily indicative of theresults of operations expected in future years.

46

Selected Combined Reserves and Land Holding Information

The follow table sets out selected combined reserves and land holding information after giving effect to the AltiaAcquisition and the Greater Hinton Acquisition.

Important information concerning the oil and natural gas reserves of the Company is contained under the heading“Statement of Reserves Data and Other Oil and Gas Information”. Readers are encouraged to carefully review thatsection of the prospectus as the information set forth in the table below is a summary only and is qualified in itsentirety by the more detailed information contained in that section.

TourmalineAltia

AcquisitionGreater Hinton

Acquisition Combined

Reserves(1)Total Proved reserves(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Light and Medium Crude Oil (Mbbls) . . . . . . . . . . . . . . . . . . . . . 1,869 15.8 18.0 1,902.8Natural Gas (MMcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 185,412 11,061.0 116,278.0 312,751.0NGL (Mbbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,107 261.0 110.0 2,478.0Total Oil Equivalent (Mboe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34,878 2,120.3 19,507.7 56,506.0

Total Proved Plus Probable Reserves(1) . . . . . . . . . . . . . . . . . . . . . .Light and Medium Crude Oil (Mbbls) . . . . . . . . . . . . . . . . . . . . . 4,740 28.3 25.0 4,793.3Natural Gas (MMcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 307,116 16,571.0 202,748.0 526,435.0NGL (Mbbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,462 384.6 192.0 4,038.6Total Oil Equivalent (Mboe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59,388 3,174.7 34,008.3 96,571.0

Developed and Undeveloped land holdings(2)Gross Acres . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 907,000 153,000 296,000 1,356,000Net Acres . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 674,000 66,000 221,000 961,000

Notes:(1) As at December 31, 2009, in respect of Tourmaline based upon the Reserve Reports (and includes Exshaw without reduction to reflect the 9.4%

third-party minority interest in Exshaw), as at March 31, 2009 in respect of Altia based on the Sproule Altia Reserve Report and as atNovember 30, 2009 in respect of the assets acquired pursuant to the Greater Hinton Acquisition based on the AJM Greater Hinton ReserveReport. The combined volume is an arithmetic sum of multiple estimates of proved or proved plus probable reserves, respectively, as containedin these reports, which have been prepared by different engineers as of different dates. See “Risk Factors – Reserve Estimates.”

(2) As at November 8, 2010.

MANAGEMENT’S DISCUSSION AND ANALYSIS

The following management’s discussion and analysis of financial condition and results of operations should beread in conjunction with the unaudited interim consolidated financial statements of Tourmaline and the notes theretofor the three and nine months ended September 30, 2010 and 2009 and the audited consolidated financial statementsand the notes thereto of Tourmaline for the year ended December 31, 2009.

The following management’s discussion and analysis is a review of the Company’s financial condition and resultsof operations as at and for the year ended December 31, 2009 and for the period from incorporation on July 21, 2008 toDecember 31, 2008, and as at and for the three and nine month periods ended September 30, 2010 and 2009. Thediscussion and analysis below has been prepared as at the date of this prospectus. The information has beensummarized from the Company’s financial statements for these periods, and should only be read in conjunction withthe remainder of this prospectus, including the Company’s financial statements and related notes and the pro formaconsolidated financial statements of the Company, all of which have been prepared in accordance with CanadianGAAP.

Certain information contained in this management’s discussion and analysis of the Company’s financial conditionand results of operations constitute forward-looking statements. These statements relate to future events or to theCompany’s future financial performance and involve known and unknown risks, uncertainties and other factors thatmay cause the Company’s actual results, levels of activity, performance or achievements to be materially differentfrom any future results, levels of activity, performance or achievements expressed or implied by such forward lookingstatements. See “Forward-Looking Statements” and “Risk Factors”.

47

The Company’s financial condition and the results of operations discussed below will not necessarily be indicativeof the Company’s future performance, as they reflect the nature of the Company’s activities to date. The Companyexpects that its general and administrative expenses as a public company will be higher than those reflected in thefinancial statements included in this prospectus and in the following discussion and analysis. The historical financialinformation in this prospectus does not reflect the added costs the Company expects to incur as a public entity.

Non-GAAP Financial Measures

This management’s discussion and analysis includes references to financial measures commonly used in the oiland gas industry such as “funds from operations”, “operating netback”, “net debt” and “working capital (adjusted forthe fair value of financial instruments and future taxes)”, which do not have any standardized meaning prescribed byGAAP. Management believes that in addition to net income, funds from operations, operating netback, net debt andworking capital (adjusted for the fair value of financial instruments and future taxes) are useful supplemental measuresas they are a measure of Tourmaline’s ability to generate the cash necessary to repay debt or fund future growththrough capital investment. However, investors are cautioned that these measures should not be construed as analternative to net income determined in accordance with GAAP as an indication of Tourmaline’s performance.Tourmaline’s method of calculating these measures may differ from other companies and, accordingly, they may notbe comparable to similar measures used by other companies. For these purposes, Tourmaline defines funds fromoperations as cash provided by operations before changes in non-cash working capital, defines operating netback asrevenue less royalties, transportation costs and operating expenses and defines working capital (adjusted for the fairvalue of financial instruments and future taxes) as working capital excluding the fair value of financial instruments andfuture taxes. Net debt is defined as long-term bank debt plus working capital (adjusted for the fair value of financialinstruments and future taxes).

Funds from Operations

A summary of the reconciliation of funds from operations to cash flow from operating activities is set forth below.

Three Months Ended Year EndedDecember 31, 2009

Period EndedDecember 31, 2008(1)(000s) December 31, 2009 December 31, 2008

Cash flow from operating activities . . . . . . $ (9,388) $522 $ (514) $522Change in non-cash working capital . . . . . . 23,957 280 22,236 280

Funds from operations . . . . . . . . . . . . . . . $14,569 $802 $21,722 $802

Note:(1) Period from incorporation on July 21, 2008 to December 31, 2008.

Three Months Ended Nine Months Ended

(000s) September 30, 2010 September 30, 2009 September 30, 2010 September 30, 2009

Cash flow from operating activities . . . . . . $41,163 $ 7,331 $97,999 $ 8,874Change in non-cash working capital . . . . . (9,435) (3,987) (8,348) (1,720)

Funds from operations . . . . . . . . . . . . . . $31,728 $ 3,344 $89,651 $ 7,154

Funds from operations in the third quarter of 2010 exceeded that of the comparable period in 2009 by$28.4 million due to higher production volumes and commodity prices in 2010 compared to 2009.

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Operating Netback

Operating netback is calculated on a per Boe basis and is defined as revenue less royalties, transportation costsand operating expenses, as shown below.

($/Boe)Three Months EndedDecember 31, 2009

Year EndedDecember 31, 2009

Revenue, excluding processing fee income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $35.59 $29.28Royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3.24) (3.79)Transportation costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1.69) (1.40)Operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (7.94) (6.51)

Operating netback . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $22.72 $17.58


($/Boe)September 30,

2010September 30,

2009 ChangeSeptember 30,

2010September 30,

2009 Change

Revenue, excluding processing feeincome . . . . . . . . . . . . . . . . . . . . . . . . . . $29.94 $20.81 44% $32.95 $22.20 48%

Royalties . . . . . . . . . . . . . . . . . . . . . . . . . . (2.80) (3.99) (30)% (3.18) (4.41) (28)%Transportation costs . . . . . . . . . . . . . . . . . . (1.78) (1.14) 56% (1.71) (1.08) 58%Operating expenses . . . . . . . . . . . . . . . . . . (6.24) (5.72) 9% (6.75) (4.89) 38%

Operating netback . . . . . . . . . . . . . . . . . . $19.12 $ 9.96 92% $21.31 $11.82 80%

The majority of the increase in operating netback in the third quarter of 2010, compared to the same quarter in2009, reflects significant commodity price improvements, the addition of a crude oil component in the product mix andlower royalty rates. See below for further discussion on the changes in royalties and operating expenses.

Working Capital (Adjusted for the Fair Value of Financial Instruments and Future Taxes)

A summary of the reconciliation of working capital to working capital (adjusted for the fair value of financialinstruments and future taxes) is set forth below.

As at

(000s)September 30,

2010December 31,

2009December 31,

2008

Working capital (deficit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $(65,154) $161,514 $314,743Future taxes – short-term liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,473 — —Fair Value of financial instruments – short-term asset . . . . . . . . . . . . . . . . . . (16,633) (324) —

Working capital (deficit) (adjusted for the fair value of financial instrumentsand future taxes) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $(78,314) $161,190 $314,713

Net Debt

A summary of the reconciliation of bank debt to net debt is set forth below.

As at

(000s)September 30,

2010December 31,

2009December 31,

2008

Bank Debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (41,186) $ — $ —Working Capital (deficit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (65,154) 161,514 314,743Future taxes – short-term liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,473 — —Fair value of financial instruments – short-term asset . . . . . . . . . . . . . . . . . . . (16,633) (324) —

Net Debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $(119,500) $161,190 $314,743

49

Selected Annual Information

2009 2008

ProductionCrude oil and NGL (Bbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 119,347 —Natural gas (Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,850,937 —Oil equivalent (Boe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,261,170 —Crude oil and NGL (Bbls/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 327 —Natural gas (Mcf/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18,770 —Oil equivalent (Boe/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,455 —

Financial($ thousands, except as noted)Gross revenue, net of royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35,127 1,237Cash flow from operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (514) 522Funds from operations (1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21,722 802Per diluted share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.31 0.04Net (loss)/earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,121) 438Per share (basic and diluted) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (0.03) 0.02Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,003,882 321,779Working capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 161,514 314,743Working capital (adjusted for the fair value of financial instruments and future taxes) (1) . . . . . . . 161,190 314,743Long-term financial liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — —Capital Expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 499,258 3,575Basic outstanding shares (000s) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101,809 53,000

Per UnitNatural gas ($/Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.24 —Crude oil and NGL ($/Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66.10 —Revenue ($/Boe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29.28 —Operating netback (1) ($/Boe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.58 —

Note:(1) See “GAAP and Non-GAAP Financial Measures” and “Management’s Discussion and Analysis – Non-GAAP Financial Measures”.

The changes to the financial information summarized above over the two periods are due primarily to the growthin the Company’s crude oil, natural gas and NGL production in the year ended December 31, 2009, from theacquisition of producing properties in 2009, including five significant acquisitions for an aggregate purchase price ofapproximately $478.2 million, and two additional equity financings totalling approximately $348.4 million completedin 2009 to fund those acquisitions and the Company’s ongoing exploration and development program. Additionalinformation regarding these items, including the Company’s acquisition, exploration, and development activities andexpenditures, and related financing activities, during these periods is found under “Description of the Business –Three-Year History Overview of Acquisitions and Equity Financings” and “Management’s Discussion and Analysis –Year Ended December 31, 2009 Compared to Period Ended December 31, 2008”.

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Selected Quarterly Information

2010 2009 2008

Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4

ProductionCrude oil and NGL (Bbls) . . . . . . . . . . . . 147,997 178,787 138,068 90,978 21,168 6,026 1,175 —Natural gas (Mcf) . . . . . . . . . . . . . . . . . . 9,502,337 8,693,492 5,449,027 3,454,934 2,067,940 1,160,021 168,042 —Oil equivalent (Boe) . . . . . . . . . . . . . . . . 1,731,720 1,627,702 1,046,239 666,800 365,825 199,363 29,182 —Crude oil and NGL (Bbls/d) . . . . . . . . . . 1,609 1,965 1,534 989 230 66 13 —Natural gas (Mcf/d) . . . . . . . . . . . . . . . . . 103,286 95,533 60,545 37,554 22,478 12,747 1,867 —Oil equivalent (Boe/d) . . . . . . . . . . . . . . . 18,823 17,887 11,625 7,248 3,976 2,191 324 —

Financial ($000s, unless otherwisenoted)

Gross revenue, net of royalties . . . . . . . . 54,232 46,634 52,749 22,483 6,414 4,591 1,639 1,237Cash flow from operating activities . . . . 41,163 34,713 22,123 (9,388) 7,331 981 562 522Funds from operations(1) . . . . . . . . . . . . . 31,728 34,015 23,908 14,569 3,344 3,074 736 802Per diluted share . . . . . . . . . . . . . . . . . . . 0.25 0.27 0.21 0.12 0.05 0.05 0.01 0.02Net earnings (loss) . . . . . . . . . . . . . . . . . . 4,463 (672) 13,354 (369) (2,081) 235 94 438Per share (basic and diluted) . . . . . . . . . . 0.04 (0.01) 0.12 0.00 (0.03) 0.00 0.00 0.01Total assets . . . . . . . . . . . . . . . . . . . . . . . 1,540,236 1,411,166 1,375,112 1,003,882 561,339 496,317 331,267 321,779Working capital . . . . . . . . . . . . . . . . . . . . (65,154) (13,083) 243,607 161,514 84,622 314,613 274,162 314,743Working capital (adjusted for the fair

value of financial instruments andfuture taxes)(1) . . . . . . . . . . . . . . . . . . . (78,314) (22,075) 234,362 161,190 84,622 313,901 274,163 314,743

Capital Expenditures . . . . . . . . . . . . . . . . 152,422 286,898 158,762 125,946 234,352 97,643 41,317 3,575Basic outstanding shares (000s) . . . . . . . 123,841 122,691 120,191 101,809 73,553 70,000 53,000 53,000

Per UnitNatural gas ($/Mcf) . . . . . . . . . . . . . . . . . 4.36 4.61 5.41 5.08 3.05 3.76 4.86 —Crude oil and NGL ($/Bbl) . . . . . . . . . . . 70.49 72.49 78.29 68.02 61.27 58.29 44.77 —Revenue ($/Boe) . . . . . . . . . . . . . . . . . . . 29.94 32.58 38.53 35.59 20.81 23.66 29.79 —Operating netback ($/Boe)(1) . . . . . . . . . . 19.12 21.82 24.16 22.30 9.96 14.98 13.63 —

Notes:(1) See “GAAP and Non-GAAP Financial Measures” and “Management’s Discussion and Analysis – Non-GAAP Financial Measures”.(2) Certain amounts have been restated for purchase price adjustments relating to property acquisitions which occurred in prior periods.

The changes to the financial information summarized above are due primarily to the continuing growth in theCompany’s crude oil, natural gas and NGL production over the periods, from the acquisition of producing properties,including seven significant acquisitions for an aggregate purchase price of approximately $854.0 million, and theCompany’s exploration and development program combined with stronger natural gas prices in 2010, and six equityfinancings totalling approximately $923.6 million since inception to fund those acquisitions and the Company’songoing exploration and development program. Additional information regarding these items including with respect tothe Company’s acquisition, exploration, and development activities and expenditures, and related financing activities,during these periods is found under “Description of the Business – Three-Year History – Overview of Acquisitions andEquity Financings”, “Management’s Discussion and Analysis – Three and Nine Months Ended September 30, 2010Compared to Three and Nine Months Ended September 30, 2009” and “Management’s Discussion and Analysis – YearEnded December 31, 2009 Compared to Period Ended December 31, 2008”.

Three and Nine Months Ended September 30, 2010 Compared to Three and Nine Months Ended September 30,2009

Production

Tourmaline produced 1,731,720 Boe in the third quarter of 2010, averaging 18,823 Boe/d compared to an averagerate of 3,976 Boe/d during the third quarter of 2009. Production on a quarter-over-quarter basis grew as new wells werebrought on-stream from the 2009 and 2010 exploration and development programs and from significant acquisitionswhich occurred during 2009 and in the first half of 2010. The third quarter of 2010 production was 91% natural gasweighted, compared to a natural gas weighting of 94% for the third quarter of 2009. Tourmaline’s crude oil and NGLproduction in the third quarter of 2010 declined from the second quarter of 2010 due in part to the disposition of a non-core oil property in June of 2010.

51

Production for the nine months ended September 30, 2010 averaged 16,138 Boe/d as compared to 2,177 Boe/d forthe nine months ended September 30, 2009. The significant increase in production is attributable to the Company’sexploration and development program and significant acquisitions completed in 2009 and 2010.


September 30,2010

September 30,2009

September 30,2010

September 30,2009

Natural gas (Mcf/d) . . . . . . . . . . . . . 103,286 22,478 86,611 12,440Crude oil and NGL (Bbls/d) . . . . . . 1,609 230 1,703 104Oil equivalent (Boe) . . . . . . . . . . . . 1,731,720 365,825 4,405,661 594,370Oil equivalent (Boe/d) . . . . . . . . . . 18,823 3,976 16,138 2,177

Revenue and Royalties

Revenue from the sale of crude oil, natural gas and NGL for the quarter ended September 30, 2010 was $51.8million compared to $7.6 million for the third quarter of 2009. Similarly, revenue grew from $13.2 million for the ninemonths ended September 30, 2009 to $145.2 million for the nine months ended September 30, 2010. Revenue growthfor the third quarter of 2010 and the nine months ended September 30, 2010, when compared to the three and ninemonths ended September 30, 2009, is comprised of production increases through acquisitions and the Company’sexploration and development program combined with stronger natural gas prices. Revenue includes all petroleum,natural gas and NGL sales and realized gains on financial instruments.

The realized average natural gas price was $4.36/Mcf ($4.69/Mcf – nine months ended September 30, 2010) andthe realized crude oil and NGL prices averaged $70.49/Bbl ($73.57/Bbl – nine months ended September 30, 2010) forthe third quarter of 2010. Realized prices exclude the effect of unrealized gains or losses. Once these gains and lossesare realized they are included in the per unit amounts. The natural gas price for the third quarter of 2010 was 24% (14%– nine months ended September 30, 2010) higher than the AECO benchmark due to a combination of higher heatcontent on the Company’s Alberta Deep Basin natural gas production and positive commodity contracts.

Tourmaline’s revenue is analyzed as follows:


(000s)September 30,

2010September 30,

2009September 30,

2010September 30,

2009

Revenue from:Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $41,408 $6,313 $110,980 $11,495Crude oil and NGL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,435 1,298 34,206 1,702

Total revenue from crude oil, natural gas and NGLsales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $51,843 $7,611 $145,186 $13,197

Tourmaline Prices


September 30,2010

September 30,2009 Change

September 30,2010


Natural gas ($/Mcf) . . . . . . . . . . . . . . . . . . $ 4.36 $ 3.05 43% $ 4.69 $ 3.38 39%Crude oil and NGL ($/Bbl) . . . . . . . . . . . . $70.49 $61.27 15% $73.57 $59.95 23%Oil equivalent ($/Boe) . . . . . . . . . . . . . . . . $29.94 $20.81 44% $32.95 $22.20 48%

Benchmark Crude Oil and Natural Gas Prices


September 30,2010


September 30,2010


Natural gasNYMEX Henry Hub (US$/Mcf) . . . . . . $ 4.21 $ 3.44 22% $ 4.52 $ 3.90 16%AECO (Cdn$/Mcf) . . . . . . . . . . . . . . . . $ 3.53 $ 2.98 18% $ 4.12 3.78 9%

Crude oilNYMEX (US$/Bbl) . . . . . . . . . . . . . . . . $75.92 $68.24 11% $77.62 57.32 35%Edmonton Par (Cdn$/Bbl) . . . . . . . . . . . $74.90 $72.22 4% $77.26 63.42 22%

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Currency Exchange Rates


September 30, 2010 September 30, 2009 Change September 30, 2010 September 30, 2009 Change

Cdn/US$ . . . . . . . . . . . . $0.9615 $0.9111 6% $0.9650 $0.8554 13%

Tourmaline’s royalties are summarized as follows:



Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . $2,433 $ 894 $ 5,993 $1,932Crude oil and NGL . . . . . . . . . . . . . . . . . . . 2,413 566 8,003 687

Total royalties . . . . . . . . . . . . . . . . . . . . . . $4,846 $1,460 $13,996 $2,619

For the quarter ended September 30, 2010, the average effective royalty rate was 9.3%, compared to 19.2% for thesame quarter in 2009. During the third quarter of 2010, the Company benefited from government incentive programsincluding the Natural Gas Deep Drilling Program and the New Well Royalty Reduction Program. Tourmaline alsobenefitted from the government incentive programs during the nine months ended September 30, 2010, resulting in asimilar decrease in the average effective royalty rate from 20% for the nine months ended September 30, 2009 to 9.6%for the nine months ended September 30, 2010.

Other Income

For the quarter ended September 30, 2010, other income was $0.4 million compared to $0.3 million for the thirdquarter of 2009. Tourmaline had a nominal amount of investments during the third quarter of 2010, resulting in adecrease in interest income, which was offset by increased processing income. Other income for the nine months endedSeptember 30, 2010 was $0.8 million compared to $2.1 million for the nine months ended September 30, 2009. Thedecrease was primarily due to lower investment income during the period.

Operating Expenses

Operating expenses include all periodic lease and field level expenses and exclude income recoveries fromprocessing third-party volumes. Operating expenses for the quarter ended September 30, 2010 were $10.8 million or$6.24/Boe, compared to $2.1 million or $5.72/Boe for the same quarter in 2009. However, the Company realized alower operating cost per Boe in the third quarter of 2010, compared to the first quarter ($7.22/Boe) and second quarter($6.98/Boe) of 2010 due to operational efficiencies partially offset by numerous workovers and transitional costsincurred on recent property acquisitions. Tourmaline’s operating expenses in the third quarter of 2010 include thirdparty processing, gathering and compression fees of approximately $3.2 million or 30% of total operating costs.

Operating expenses averaged $6.75/Boe for the nine months ended September 30, 2010 compared to $4.89/Boefor the same period in 2009. Tourmaline’s operating expenses per barrel of oil equivalent were anomalously low for thethree and nine months ended September 30, 2009 as Tourmaline only had one significant producing asset for themajority of these periods. The Company has identified a number of opportunities to reduce per unit operating costs andexpects to achieve further reductions throughout the rest of 2010 and 2011 as higher-productivity wells are brought on-stream and a greater percentage of Tourmaline’s production base is redirected through Company-owned and operatednatural gas processing facilities.

General & Administrative Expenses

During the third quarter of 2010, G&A expenses of $2.5 million, including $0.7 million related to stock-basedcompensation expense, were incurred. The Company also capitalized direct G&A costs of $1.4 million and stock-basedcompensation of $0.7 million in the third quarter of 2010. G&A expense per Boe, excluding interest, financing charges,stock-based compensation and capitalized G&A, was $0.95/Boe for the third quarter of 2010, compared to $1.04/Boefor the second quarter of 2010 and $1.44/Boe for the first quarter of 2010, as unit efficiencies continue to be realizedfrom a larger production base. The Company expects this trend of reducing G&A expenses per Boe to continue into2011 as production volumes grow more rapidly than the associated overhead costs.

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For the nine months ended September 30, 2010, G&A expenses totalled $7.0 million (September 30, 2009 – $2.5million) including $2.0 million (September 30, 2009 – $0.6 million) related to stock-based compensation expense.During the same period, direct G&A costs of $4.3 million (September 30, 2009 – $1.3 million) and stock-basedcompensation of $1.7 million (September 30, 2009 – $0.6 million) were capitalized. The increase in G&A expenses forthe first nine months of 2010 compared to the same period in 2009 are primarily due to office staff additions and higherrent expense as the Company took on more head office space. The higher total G&A expenses allow the Company tomanage the commensurately larger production, reserve and land base. Notwithstanding this, the Company’s G&Aexpenses per Boe continue to trend downward as Tourmaline’s production base continues to grow faster than itsaccompanying G&A costs. G&A costs, excluding interest, financing charges, stock-based compensation andcapitalized G&A, for the nine months ended September 30, 2010 were $1.09 per Boe, compared to $3.27 per Boe forthe first nine months of 2009. This decrease in per Boe G&A cost is consistent with a growing production base.

Tourmaline’s G&A expenses are summarized as follows:



G&A expenses . . . . . . . . . . . . . . . . . . . . . . $ 4,723 $1,380 $13,404 $ 3,756Administrative and operating recovery . . . (420) (25) (1,185) (25)Capital recovery . . . . . . . . . . . . . . . . . . . . . (1,227) (302) (3,072) (505)Capitalized G&A . . . . . . . . . . . . . . . . . . . . (1,440) (490) (4,346) (1,285)Interest and financing charges . . . . . . . . . . 170 — 208 —Stock-based compensation . . . . . . . . . . . . . 1,436 464 3,711 1,186Capitalized stock-based compensation . . . (699) (232) (1,704) (593)

Total G&A . . . . . . . . . . . . . . . . . . . . . . . . $ 2,543 $ 795 $ 7,016 $ 2,534

Stock-Based Compensation

Tourmaline uses the fair value method for the determination of all non-cash related stock-based compensation.During the third quarter of 2010, Options to purchase 2,097,000 Common Shares were granted to employees, officers,directors and consultants at a weighted average exercise price of $18.33 per share. The Company recognized $0.7million of stock-based compensation expense in the third quarter of 2010, compared to $0.2 million in the third quarterof 2009. For the nine months ended September 30, 2010, the Company recognized $2.0 million (September 30, 2009 –$0.6 million) of stock-based compensation expense.

Depreciation, Depletion and Accretion (“DD&A”)

DD&A expense was $31.2 million for the third quarter of 2010 compared to $5.7 million for the same period in2009 due to higher production volumes and a higher DD&A rate per Boe. The DD&A rate per Boe for the third quarterof 2010 was $18.04/Boe compared to $15.70/Boe for the third quarter of 2009 and $19.70/Boe for the second quarterof 2010. For the nine months ended September 30, 2010, DD&A expense was $85.3 million (September 30, 2009 –$8.7 million) with an effective rate of $19.36/Boe (September 30, 2009 – $14.57/Boe). The DD&A rate per Boe in thecurrent year is trending downward due to the nature and size of the acquisitions completed by the Company and recentdrilling results.

Cash Flow from Operations, Funds from Operations and Net Earnings

Cash flow from operations increased from $7.3 million for the three months ended September 30, 2009 to $41.2million for the same period in 2010. Similarly, cash flow from operations for the nine months ending September 30,2010 increased to $98.0 million from $8.9 million for the same period in the previous year. The increases in cash flowfrom operations are due to production growth and strengthening commodity prices.

Funds from operations for the third quarter of 2010 were $31.7 million or $0.25 per diluted share, compared tofunds from operations of $3.3 million or $0.05 per diluted share for the third quarter of 2009. The Company earnedafter-tax income for the three months ended September 30, 2010 in the amount of $4.5 million, compared to the

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after-tax loss of $2.1 million for the three months ended September 30, 2009. For the nine months ended September 30,2010, Tourmaline had after-tax earnings of $17.1 million or $0.14 per diluted share.


September 30, 2010 September 30, 2009 September 30, 2010 September 30, 2009

Cash flow from operations per share(1) . . . $ 0.32 $ 0.12 $ 0.81 $ 0.15Funds from operations per share(1)(2) . . . . . $ 0.25 $ 0.05 $ 0.74 $ 0.13Earnings (loss) per share(1) . . . . . . . . . . . . . $ 0.04 $(0.03) $ 0.14 $ (0.03)Operating netback(2) per Boe . . . . . . . . . . . $19.12 $ 9.96 $21.31 $11.82

Notes:(1) Fully diluted.(2) See “GAAP and Non-GAAP Financial Measures” and “Management’s Discussion and Analysis – Non-GAAP Financial Measures”.


During the three months ended September 30, 2010, the Company invested $152 million of cash considerationcompared to $234 million for the same period in 2009. Expenditures on exploration and production in the third quarterof 2010 were $147 million compared to $48 million in the same quarter of 2009, which is consistent with theCompany’s aggressive growth strategy. The Company drilled 21 gross (15.26 net) wells, completed 34 gross (27.2 net)wells and tied-in 14 gross (9.17 net) wells during the third quarter of 2010. Drilling, completing, equipping and relatedfacilities costs totalled $128.8 million, land costs were $14.7 million, seismic expenditures were $2.3 million andproperty acquisitions, net of dispositions, were $5.1 million for the third quarter of 2010. Included in the third quarterof 2010 acquisitions was a significant working interest in a gas processing facility with a net capacity of 45 MMcf/d inthe Alberta Deep Basin.

During the nine months ended September 30, 2010, Tourmaline disposed of certain non-core producing and non-producing properties for aggregate proceeds of $25.1 million. Included in the proceeds was an investment in a privateoil and gas corporation valued at $3.25 million.



Land and seismic . . . . . . . . . . . . . . . . . . . . $ 16,993 $ 12,530 $ 29,365 $ 14,141Drilling and completions . . . . . . . . . . . . . . 89,121 31,932 207,312 53,030Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . 39,702 3,082 85,952 4,526Property acquisitions . . . . . . . . . . . . . . . . . 17,116 187,050 289,400 300,545Corporate acquisition . . . . . . . . . . . . . . . . . — (744) 3,156 (744)Property disposition . . . . . . . . . . . . . . . . . . (11,971) — (21,834) —Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,461 502 4,731 1,814

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $152,422 $234,352 $598,082 $373,312

Liquidity and Capital Resources

At September 30, 2010, Tourmaline had negative working capital of $78.3 million, after adjusting for the fairvalue of financial instruments and future taxes (the unadjusted working capital deficiency was $65.2 million). TheCompany has sufficient liquidity and capital resources to fund its 2010 exploration and development program throughexpected cash flow from operations and its unutilized Credit Facilities.

On March 19, 2010, Tourmaline closed a private placement equity financing for gross proceeds of approximately$224 million. The transaction included the issuance of 9.5 million Common Shares at $18.00 per share and2.45 million Flow-Through Shares at $21.60 per share. The net proceeds of approximately $214 million were utilizedto acquire properties and to conduct the Company’s 2010 exploration and development program.

Tourmaline issued 2.5 million Common Shares on June 1, 2010 as part of a property acquisition that closed in thesecond quarter of 2010.

On August 12, 2010, the Company issued 1.15 million Flow-Through Shares at $22.00 per share, for grossproceeds of $25.3 million.

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The Credit Facilities include the Tourmaline Revolving Facility, an extendible revolving term loan in the amountof $100.0 million and the Tourmaline Operating Facility, a $15.0 million operating line. The Credit Facilities alsoinclude the Exshaw Revolving Facility, an extendible revolving term loan in the amount of $5.0 million and theExshaw Operating Facility, a $5.0 million operating line. See “Consolidated Capitalization”.

On completion of the Offering and the Concurrent Private Placement, the Company will have sufficient liquidityand capital resources to fund its budgeted $425 million 2011 capital exploration and development program from the netproceeds of the Offering and the Concurrent Private Placement, cash generated from operations and draws under theCredit Facilities.

Flow-Through Commitments

At September 30, 2010, the Company had fulfilled the $31.5 million Flow-Through Shares Canadian explorationexpense commitment undertaken in 2009.

On March 19, 2010, the Company issued 2.45 million Flow-Through Shares committing the Company to spend$52.9 million on eligible capital expenditures by December 31, 2011, of which $51.7 million had been expended as atSeptember 30, 2010.

On August 12, 2010, the Company issued 1.15 million Flow-Through Shares committing the Company to spend$25.3 million on eligible capital expenditures prior to December 31, 2011, none of which has been expended to date.

Shares Outstanding

As at November 15, 2010, the Company had 123,841,060 Common Shares outstanding and 11,772,000 CommonShares reserved for issuance upon the exercise of issued and outstanding Options.

Subsequent Events

On November 1, 2010, Tourmaline acquired certain petroleum and natural gas properties and related assets in theAlberta Deep Basin for a cash purchase price of approximately $52 million, before closing adjustments pursuant to theDeep Basin West Acquisition. The purchase price was funded by a draw under the Tourmaline Revolving Facility. See“Recent Developments – Deep Basin West Acquisition” for additional information on the Acquired Assets and theDeep Basin West Acquisition.

The Company has entered into the Underwriting Agreement providing for the issue and sale of 10,000,000Common Shares (11,500,000 Common Shares if the Over-Allotment Option is exercised in full) priced at $21.00 perCommon Share pursuant to the Offering resulting in estimated gross proceeds of $210.0 million less the Underwriters’Commission of $11.55 million and estimated Offering expenses of $3.75 million assuming no exercise of the Over-Allotment Option and resulting in estimated gross proceeds of $241.5 million less the Underwriters’ Commission of$13,282,500 and estimated Offering expenses of $3.75 million assuming the full exercise of the Over-AllotmentOption.

In addition, the Company has entered into subscription agreements with the Private Placees pursuant to which thePrivate Placees will purchase, pursuant to the Concurrent Private Placement, an aggregate of 850,000 Common Sharesat the Offering Price for gross proceeds to the Company of $17.85 million.

Commitments and Contractual Obligations

In the normal course of business, Tourmaline is obligated to make the following future payments. Theseobligations represent contracts and other commitments that are known and non-cancellable.

Payments Due by Year

(MM) Total 2010 2011 2012 2013 2014 and on

Operating leases . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 8,831 $ 587 $ 2,348 $ 2,120 $ 1,758 $ 2,018Flow-Through obligations . . . . . . . . . . . . . . . . . . . . . 26,493 — 26,493 — — —Firm transportation agreements . . . . . . . . . . . . . . . . . 68,012 $ 3,522 $17,447 $17,213 $14,901 $14,929

$103,336 $ 4,109 $46,288 $19,333 $16,659 $16,947

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Financial Risk Management

The Board of Directors has overall responsibility for the establishment and oversight of the Company’s riskmanagement framework. The Board has implemented and monitors compliance with risk management policies. TheCompany’s risk management policies are established to identify and analyze the risks faced by the Company, to setappropriate risk limits and controls and to monitor risks and adherence to controls and the Company’s activities.

Fair value of financial instruments

Financial instruments comprise cash and cash equivalents, accounts receivable, investments, accounts payable andaccrued liabilities, commodity risk management contracts and bank debt. The fair values of cash and cash equivalents,accounts receivable, accounts payable and accrued liabilities and approximate their carrying amounts due to their short-term maturities. The Company’s investments held for trading were fair valued at September 30, 2010 andDecember 31, 2009 and in each case were classified as Level 1.

The fair value of the risk management contracts (as presented on the balance sheet) are determined by discountingthe difference between the contracted price and published forward price curves as at the balance sheet date, using theremaining contracted oil and natural gas volumes, and are considered Level 2.

Bank debt bears interest at a floating market rate and accordingly the fair value approximates the carrying value.

Credit risk

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument failsto meet its contractual obligations, and arises principally from the Company’s receivables from joint venture partners,petroleum and natural gas marketers and commodity price risk contracts. As at September 30, 2010, Tourmaline’sreceivables consisted of $19.5 million (December 31, 2009 – $13.7 million) from joint venture partners, $16.7 million(December 31, 2009 – $11.1 million) from petroleum and natural gas marketers and $16.8 million (December 31, 2009– $20.3 million) from provincial and federal governments.

Receivables from petroleum and natural gas marketers are normally collected on the 25th day of the monthfollowing production. The Company’s policy to mitigate credit risk associated with these balances is to establishmarketing relationships with creditworthy purchasers. The Company historically has not experienced any collectionissues with its petroleum and natural gas marketers. The Company applies the same policy when establishingrelationships with counterparties in commodity price risk management contracts. Joint venture receivables are typicallycollected within one to three months of the joint venture bill being issued to the partner. The Company attempts tomitigate the risk from joint venture receivables by obtaining partner approval of significant capital expenditures priorto expenditure. However, the receivables from participants in the petroleum and natural gas sector and collection of theoutstanding balances is dependent on industry factors such as commodity price fluctuations, escalating costs and therisk of unsuccessful drilling. In addition, further risk exists with joint venture partners as disagreements occasionallyarise that increase the potential for non-collection. The Company does not typically obtain collateral from petroleumand natural gas marketers or joint venture partners; however, the Company does have the ability to withhold productionfrom joint venture partners in the event of non-payment.

The Company monitors the age of, and investigates issues behind, its receivables that are past due for over 60days. At September 30, 2010, the Company had $2.5 million (December 31, 2009 – $251,000) receivables over 90days. The Company is satisfied that these amounts are substantially collectible.

The carrying amount of accounts receivable, cash and cash equivalents represents the maximum credit exposure.The Company does not have an allowance for doubtful accounts as at September 30, 2010 (December 31, 2009 and2008 – nil) and did not provide for any doubtful accounts, nor was it required to write-off any receivables, during thenine months ended September 30, 2010 (December 31, 2009 and 2008 – nil).

Liquidity risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they come due. TheCompany’s approach to managing liquidity is to ensure, as far as possible, that it will have sufficient liquidity to meetits liabilities when due, under both normal and stressed conditions without incurring unacceptable losses or riskingharm to the Company’s reputation. Liquidity risk is mitigated by cash on hand and the Credit Facilities.

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The Company’s accounts payable and accrued liabilities balance at September 30, 2010 was approximately$134.1 million (December 31, 2009 – $86.9 million). It is the Company’s policy to pay suppliers within 45-75 days.These terms are consistent with industry practice. As at September 30, 2010, substantially all of the account balanceswere less than 90 days.

The Company prepares annual capital expenditure budgets, which are regularly monitored and updated asconsidered necessary. Further, the Company utilizes authorizations for expenditures on both operated and non-operatedprojects to further manage capital expenditures. The Company also attempts to match its payment cycle with thecollection of petroleum and natural gas revenues on the 25th day of each month.

Market risk

The Company utilizes both financial derivatives and physical delivery sales contracts to manage market risks. Allsuch transactions are conducted in accordance with the risk management policy that has been approved by the Board ofDirectors.

Currency risk had minimal impact on the value of the financial assets and liabilities as presented on the balancesheet of the Company as at September 30, 2010 and December 31, 2009. Changes in the U.S. to Canadian exchangerate, however, could influence future petroleum and natural gas prices which in return, may impact the value of certainderivative contracts. This influence cannot be accurately quantified.

Interest rate risk had minimal impact on the Company’s balance sheet as at September 30, 2010 as there was anominal average amount of cash in short term investments and only small amounts drawn on the Credit Facilities overthe third quarter of 2010. At the end of the third quarter of 2010 there was a draw on the Company’s Credit Facilities of$41.2 million, which will expose the Company to interest rate risk via fluctuations in floating rate of interest on a go-forward basis.

Commodity price risk is the risk that the fair value of future cash flows will fluctuate as a result of changes incommodity prices. As at September 30, 2010, the Company has entered into certain financial derivative and physicaldelivery sales contracts in order to manage commodity risk. These instruments are not used for trading or speculativepurposes. The Company has not designated its financial derivative contracts as effective accounting hedges, eventhough the Company considers all commodity contracts to be effective economic hedges. As a result, all suchcommodity contracts are recorded on the balance sheet at fair value, with changes in the fair value recognized inpetroleum and natural gas sales. Settlements are recognized in petroleum and natural gas sales at the time eachtransaction under a contract is settled.

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The Company had entered into the following contracts as at September 30, 2010:

Type of Contract Quantity Time Period Contract Price

AECO/Nymex Differential Swap . . 3,000 MMbtu/d January – October 2010 Nymex less $0.44/MMbtu

AECO/Nymex Differential Swap . . 5,000 MMbtu/d April – October 2010 Nymex less $0.35/MMbtu

Nymex Settlement Price . . . . . . . . . 100 Bbls/d January – December 2010 US$83.75/Bbl

Nymex Settlement Price . . . . . . . . . 100 Bbls/d January – December 2011 US$87.85/Bbl

AECO Fixed Price . . . . . . . . . . . . . . 3,000 GJs/d January – December 2010 Cdn$5.63/GJ

AECO Fixed Price . . . . . . . . . . . . . . 3,000 GJs/d April 2010 – March 2011 Cdn$5.77/GJ

AECO Fixed Price . . . . . . . . . . . . . . 2,000 GJs/d April 2010 – March 2011 Cdn$5.72/GJ



AECO Fixed Price . . . . . . . . . . . . . . 4,000 GJs/d February 2010 – December 2011 Cdn$5.68/GJ

AECO Fixed Price . . . . . . . . . . . . . . 2,000 GJs/d February 2010 – December 2011 Cdn$5.72/GJ

AECO Fixed Price . . . . . . . . . . . . . . 2,000 GJs/d November 2010 – March 2011 Cdn$6.01/GJ average

AECO Fixed Price . . . . . . . . . . . . . . 2,000 GJs/d March 2010 – March 2012 Cdn$5.72/GJ average

AECO Fixed Price . . . . . . . . . . . . . . 2,000 GJs/d March 2010 – December 2011 Cdn$5.705/GJ

AECO Call Option . . . . . . . . . . . . . . 3,000 GJs/d January – December 2011 Cdn$6.50/GJ strike price

AECO Fixed Price . . . . . . . . . . . . . . 3,000 GJs/d March 2010 – March 2011 Cdn$5.89/GJ

AECO/Nymex Differential Swap . . 3,000 MMbtu/d November 2010 – October 2011 Nymex less $0.475/MMbtu

Costless Collar . . . . . . . . . . . . . . . . . 100 Bbls/d September 2010 – August 2012 US$75/Bbl floor –US$96/Bbl ceiling

AECO Call Option . . . . . . . . . . . . . . 3,000 GJs/d January 2011 – December 2012 Cdn$6.00/GJ strike price

AECO Fixed Price . . . . . . . . . . . . . . 3,000 GJs/d January 2011 – December 2012 Cdn$5.53/GJ

AECO/Nymex Differential Swap . . 5,000 MMbtu/d November 2010 – November 2012 Nymex less $0.62/MMbtu



The Company entered into the following contracts subsequent to September 30, 2010:


AECO/Nymex Differential Swap . . 5,000 MMbtu/d January – December 2011 Nymex less $0.475/MMbtuFinancial Swap . . . . . . . . . . . . . . . . 100 Bbls/d July 2011 – December 2012 $90.00 USD/Bbl

The following table provides a summary of the unrealized gains and losses on financial instruments for the threeand nine-month periods ended September 30, 2010 (September 30, 2009 – nil):

(000s)Three Months EndedSeptember 30, 2010

Nine Months EndedSeptember 30, 2010

Unrealized gain (loss) on financial instruments . . . . . . . . $6,827 $21,564Unrealized gain (loss) on investments held for

trading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (9) 73

Unrealized gain (loss) on financial instruments . . . . . $6,818 $21,637

The fair value of the outstanding contracts at September 30, 2010 totals $21.9 million, $16.6 million of which iscurrent.

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The Company had entered into the following contracts as at December 31, 2009:


AECO/Nymex Differential Swap . . . 3,000 MMbtu/d January – October 2010 Nymex less $0.44/MMbtu

AECO/Nymex Differential Swap . . . 5,000 MMbtu/d November 2009 – March 2010 Nymex less $0.25/MMbtu

AECO/Nymex Differential Swap . . . 5,000 MMbtu/d April – October 2010 Nymex less $0.35/MMbtu

Nymex Settlement Price . . . . . . . . . . 100 Bbls/d January – December 2010 US$83.75/Bbl

Nymex Settlement Price . . . . . . . . . . 100 Bbls/d January – December 2011 US$87.85/Bbl

AECO Fixed Price . . . . . . . . . . . . . . 3,000 GJs/d January – December 2010 Cdn$5.63/GJ ceiling

The following table provides a summary of the gain (loss) on financial instruments for the year endedDecember 31, 2009 (2008 – nil):

(000s) 2009

Unrealized gain on financial instruments . . . . . . . . . . . . . . . . . . . . . . . . $324Unrealized loss on investments held for trading . . . . . . . . . . . . . . . . . . . (46)

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $278

Unrealized gains and losses on financial instruments are included on the balance sheet and gains and lossesassociated with changes in fair value are recognized on the income statement. As at September 30, 2010, if the futurestrip prices for natural gas were $0.10/Mcf higher and prices for oil were $1.00/Bbl higher, with all other variables heldconstant, before-tax earnings for the period would have been $1.6 million lower. An equal and opposite impact wouldhave occurred to before-tax earnings and the fair value of the derivative contracts asset, had natural gas prices been$0.10/Mcf lower and oil prices $1.00/Bbl lower. As at December 31, 2009, if the future strip prices for natural gas were$0.10/Mcf higher and prices for oil were $1.00/Bbl higher, with all other variables held constant, before-tax earningsfor the period would have been $185,000 lower. An equal and opposite impact would have occurred to before-taxearnings and the fair value of the derivative contracts asset had natural gas prices been $0.10/Mcf lower and oil prices$1.00/Bbl lower.

Capital management

The Company’s policy is to maintain a strong capital base so as to maintain investor, creditor and marketconfidence and to sustain the future development of the business. The Company considers its capital structure toinclude shareholders’ equity, bank debt and working capital. In order to maintain or adjust the capital structure, theCompany may, from time to time, issue shares and adjust its capital spending to manage current and projected debtlevels. The annual and updated budgets are approved by the Board of Directors. The key measures that the Companyutilizes in evaluating its capital structure are total debt adjusted for unrealized gains and losses on financial instrumentsto cash flow from operations (before changes in non-cash working capital) and the available credit in relation to theCompany’s budgeted capital program. Debt adjusted for unrealized gains and losses on financial instruments to cashflow from operations (before changes in non-cash working capital) represents a measure of the time it is expected totake to pay off the debt if no further capital expenditures were incurred and if cash flow from operations beforechanges in non-cash working capital in the next year was equal to the amount in the most recent quarter annualized. AtSeptember 30, 2010, the Company had negative working capital of $78.3 million after adjusting for unrealized gains onfinancial instruments and future taxes (unadjusted working capital at September 30, 2010 was $65.2 million). AtDecember 31, 2009, the Company was in a positive working capital position of $161.2 million after adjusting forunrealized gains on financial instruments and future taxes (unadjusted working capital at December 31, 2009 was$161.5 million).

Certain holders of Common Shares are subject to trading restrictions for the earlier of three years from the date ofissue, or until the Common Shares are listed on an “Exchange” (as defined in the Escrow Agreement). The Companyhas not paid or declared any dividends since the date of incorporation. There have been no changes to the Company’sapproach to capital management since December 31, 2009.

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Year Ended December 31, 2009 Compared to Period Ended December 31, 2008

Production

Tourmaline produced 1,261,170 Boe in 2009, averaging 3,455 Boe/d. The majority of the growth in theCompany’s production during 2009 was from the acquisitions of producing assets. During 2009, the Company had nottied in natural gas wells from its exploration and development program due to weak natural gas prices. The 2009production was 91% natural gas weighted.

Three Months EndedDecember 31, 2009


Natural gas (Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,454,934 6,850,937Crude oil and NGL (Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90,978 119,347Oil equivalent (Boe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 666,800 1,261,170Oil equivalent (Boe/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,248 3,455

Revenue and Royalties

Revenue from the sale of crude oil, natural gas and NGL for the year ended December 31, 2009 was$36.9 million. Revenue includes all petroleum, natural gas and NGL sales. Realized crude oil and NGL prices averaged$66.10/Bbl and the realized average natural gas price was $4.24/Mcf for 2009. Realized prices exclude the effect ofunrealized gains or losses. Once these gains and losses are realized they are included in the per unit amounts. As theCompany had no hydrocarbon production in 2008, there was no related revenue.

Total crude oil, natural gas and NGL sales for the fourth quarter were $23.7 million which accounted forapproximately 64% of the Company’s full year revenue. The Company’s realized corporate natural gas price for thefourth quarter of 2009 was $5.08/Mcf, a 10% premium to the AECO benchmark. The Company realized a higher gasprice than the AECO benchmark due to the higher heat content of its Alberta Deep Basin natural gas and advantageouscommodity contracts.

Tourmaline’s revenue is analyzed as follows:



(000s) (000s)

Revenue from:Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $17,544 $29,038Crude oil and NGL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,188 7,889

Total revenue from crude oil, natural gas and NGL sales . . . . . . . . . . . . . . . . $23,732 $36,927

Tourmaline Prices



Natural gas ($/Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 5.08 $ 4.24Crude oil and NGL ($/Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $68.02 $66.10Oil equivalent ($/Boe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $35.59 $29.28

Benchmark Oil and Gas Prices



Natural gasNYMEX Henry Hub (US$/Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4.93 $ 4.16AECO (Cdn$/Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4.62 $ 3.99

Crude oilNYMEX (US$/Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $76.13 $62.09Edmonton Par (Cdn$/Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $77.05 $66.83

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Currency Exchange Rates



Cdn/US$ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $0.9469 $0.8768

Tourmaline’s royalties are summarized as follows:

(000s)Three Months EndedDecember 31, 2009


Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 495 $2,420Crude oil and NGL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,665 2,359

Total royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,160 $4,779

For the year ended December 31, 2009, the average effective royalty rate was 12.9%. The Company paid noroyalties in 2008.

For 2009, the Company’s royalties were based on a full year of the Alberta Government’s New RoyaltyFramework. Furthermore, Tourmaline optimized its royalties by participating in various incentive programs in bothAlberta and British Columbia, including the Natural Gas Deep Drilling Program, the New Well Royalty ReductionProgram and various drilling credit programs.

Interest Income

For the year ended December 31, 2009, interest income of $2.6 million was earned from Tourmaline’s portfolio ofcash and short-term investments. The investment portfolio is comprised primarily of Canadian treasury bills, bankers’acceptance notes and government bonds. For the period from incorporation on July 21, 2008 to December 31, 2008,interest income of $1.2 million was earned from Tourmaline’s portfolio of cash and short term investments.

Operating Expenses

Operating expenses include all periodic lease and field level expenses and exclude income recoveries for processingthird-party volumes. Operating expenses for the year ended December 31, 2009 were $8.2 million or $6.51/Boe. During thefourth quarter of 2009, higher operating expenses of $7.94/Boe were attributable to corporate acquisitions, which had ahigher percentage of oil in their asset mix. The Company’s operating expenses included third-party processing, gathering andcompression fees of approximately $4.5 million or 55% of total operating costs in 2009. For the period from incorporation onJuly 21, 2008 to December 31, 2008, there were no operating expenses as the Company had no oil and gas operations.

General & Administrative Expenses

During 2009, G&A expenses of $4.2 million, including $1.0 million related to stock-based compensation expense,were incurred. The Company also capitalized direct G&A costs including stock-based compensation and the tax-effectrelated thereto. G&A costs per Boe for the full year 2009 were $2.50/Boe, and for the fourth quarter of 2009, suchcosts improved to $1.74/Boe as unit efficiencies were being realized from a larger producing asset base. For the periodfrom incorporation on July 21, 2008 to December 31, 2008, G&A expenses of $571,000, including $136,000 of stock-based compensation were incurred with no G&A expenses being capitalized during that period.

The Company’s G&A expenses are summarized as follows:

Three Months Ended Year EndedDecember 31,

2009

Period EndedDecember 31,

2008(000s)December 31,

2009December 31,

2008

G&A expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,718 $435 $ 6,527 $435Administrative and operating recovery . . . . . . . . . . . . . . . . . . . (19) — (44) —Capital recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (809) — (1,314) —Capitalized G&A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (730) — (2,015) —Stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 696 136 1,882 136Capitalized stock-based compensation . . . . . . . . . . . . . . . . . . . (280) — (873) —

Total G&A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,576 $571 $ 4,163 $571

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Tourmaline uses the fair value method for the determination of all non-cash-related stock-based compensation.During 2009, Options to purchase 4,935,000 Common Shares were granted to employees, officers, directors andconsultants with exercise prices ranging from $8.00 to $15.00 per share and 175,000 Options were forfeited. During2008, Options to purchase 3,850,000 Common Shares were granted to employees, officers, directors and consultantswith an exercise price of $7.00 per share. The Company recognized $1.0 million of stock-based compensation expensein 2009, of which $0.4 million was recognized in the fourth quarter of 2009. Stock-based compensation expense for theperiod from incorporation on July 21, 2008 to December 31, 2008 was $135,923.

Cash Flow from Operations, Funds from Operations and Net Earnings

The Company had cash flow from operations for the three months ended December 31, 2009 of $9.4 million($0.10 per diluted share) and a loss of $0.5 million ($0.01 per diluted share) for the full year ended December 31, 2009primarily due to an increase in net working capital. Cash flow from operations for the year ended December 31, 2008were $0.5 million, attributable mainly to interest income which was received in the period earned.

Funds from operations for 2009 were $21.7 million or $0.31 per diluted share. The Company incurred an after taxloss for the year ended December 31, 2009 in the amount of $2.1 million of which $0.4 million of the loss was incurredin the fourth quarter of 2009.

For the three months ended December 31, 2009, the Company realized funds from operations of $14.6 million or$0.12 per diluted share. Funds from operations for the period from incorporation on July 21, 2008 until December 31,2008 were $0.8 million or $0.02 per diluted share. Net earnings for the same period were $0.4 million or $0.01 perdiluted share.

Three Months Ended Period Ended

December 31,2009

December 31,2008

December 31,2009

December 31,2008

Cash flow from operations per share(1) . . . . . . . . . . . . . . . . . . . $ (0.10) $(0.01) $ (0.01) $0.03Funds from operations per share(1) . . . . . . . . . . . . . . . . . . . . . . . $ 0.12 $ 0.02 $ 0.31 $0.04Earnings per share(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ 0.01 $ (0.03) $0.02Operating netback per boe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $22.72 $ — $17.58 $ —

Notes(1) Fully diluted.(2) Basic and diluted.(3) See “GAAP and Non-GAAP Financial Measures” and “Management’s Discussion and analysis- Non-GAAP Financial Measures”.


In 2009, Tourmaline successfully closed 12 different acquisitions for total consideration of approximately$595 million. These acquisitions were comprised of nine property and three private corporation purchases. In total,approximately 11,400 Boe/d of initial production was added in addition to over 500,000 acres of undeveloped land andsignificant natural gas infrastructure.

During 2009, the Company invested $499.3 million of cash consideration, the majority of which related to assetand corporate acquisitions ($351.8 million), drilling and completion of wells (and related facility charges) of$112.1 million, land sale costs of $25.6 million and $7.0 million in seismic. Capital expenditures were net of$10.3 million of drilling credits realized through the Alberta Drilling Royalty Credit Program. DD&A expense of $23.0million was incurred in 2009, with a DD&A rate of $18.26/Boe for the year.

Tourmaline issued approximately 21.3 million Common Shares at an average price of $11.44 per share forcorporate and property acquisitions, aggregating to $243.2 million in 2009.

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In addition, Tourmaline drilled 29 gross (24.8 net) wells and completed 25 gross (22.1 net) wells during the year.

Three Months Ended Year EndedDecember 31, 2009

Period EndedDecember 31, 2008(000s) December 31, 2009 December 31, 2008

Land and seismic . . . . . . . . . . . . . . . . . . . . . . $ 18,969 $3,357 $ 32,611 $3,357Drilling and completions . . . . . . . . . . . . . . . . 31,798 71 84,828 71Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22,726 — 27,253 —Property Acquisition . . . . . . . . . . . . . . . . . . . 59,849 — 360,496 —Corporate Acquisition . . . . . . . . . . . . . . . . . . (7,911) — (8,655) —Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 515 147 2,725 147

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $125,946 $3,575 $499,258 $3,575

Capital expenditures incurred during the period from incorporation on July 21, 2008 to December 31, 2008 were$3.6 million and were related primarily to land acquisitions and seismic.

Flow-Through Commitments

At December 31, 2009, Tourmaline had fully incurred the $25.0 million Flow-Through Share Canadianexploration expense commitment undertaken in 2008. The renouncement of the 2008 Canadian exploration expenses,along with the related future tax effect of $6.25 million, was recognized in the first quarter of 2009.

The Company issued a further $31.5 million of Flow-Through Shares on November 10, 2009, and fully satisfiedthe associated $31.5 million Canadian exploration expense commitment by March 31, 2010.

Commitments and Contractual Obligations

In the normal course of business, Tourmaline is obligated to make future payments. These obligations representcontracts and other commitments that are known and non-cancellable.

Payments due by period

(MM) Total <1 year 2-3 years 4-5 years

Flow-Through obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $82.8 $29.9 $52.9 $ —Transportation contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.6 0.6 — —Operating leases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.3 1.9 4.0 3.4

$92.7 $32.4 $56.9 $3.4

Disclosure Controls and Procedures

Disclosure controls and procedures have been designed to ensure that information required to be disclosed by theCompany is accumulated and communicated to the Company’s management as appropriate to allow timely decisionsregarding required disclosure.

IFRS

In February 2008, the CICA Accounting Standards Board (“AcSB”) confirmed the changeover to IFRS fromCanadian GAAP will be required for publicly accountable enterprises for interim and annual financial statementseffective for fiscal years beginning on or after January 1, 2011, including comparatives for 2010. The eventualchangeover to IFRS represents a change due to new accounting standards. The transition from current Canadian GAAPto IFRS is a significant undertaking that may materially affect the Company’s reported financial position and results ofoperations.

Project Status

The Company has completed its preliminary assessment of accounting policy alternatives and continues toevaluate the policies it will adopt. Changes in accounting policies are expected and will impact the financialstatements. The impact of potential accounting policy changes cannot yet be quantified as management continues toassess policy choices as a result of anticipated changes in IFRS prior to the conversion date.

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Tourmaline remains focused on the transition to IFRS and will be ready to prepare financial statements under bothCanadian GAAP and IFRS for 2010 to provide for comparative financial statements after the official changeover in2011. Tourmaline has been working toward the completion of the preliminary opening IFRS balance sheet as well asthe conversion of the first quarter 2010 financial statements, although certain issues and have not been concluded andthe quantifiable impacts have not yet been determined as of the date of this prospectus.

Areas of Focus

The following discussion provides additional information on the key areas of focus, which Tourmaline expects tohave the highest impact in the changeover; however, as certain aspects of the adoption of IFRS remain uncertain,Tourmaline cannot guarantee that this information will not change as the date of transition approaches. The Companywill continue to communicate information in relation to its conversion process as it becomes available.

Accounting for Capital Assets Including Impairment

Tourmaline is currently determining the Company’s accounting policies associated with capital assets under IFRS.When appropriate, the Company is electing to make policy choices that minimize the differences betweenTourmaline’s capital asset accounting under current Canadian GAAP and IFRS and also that reflect policies which areconsistent with our peer entities.

Š Exploration and Evaluation assets (“E&E”):

Š The Company’s undeveloped land balance as at December 31, 2009 will be the largest component of theopening balance of E&E at January 1, 2010. This and any other exploratory assets will be separatelydisclosed on the balance sheet and in the notes to the financial statements.

Š E&E assets will be assessed for impairment on January 1, 2010, and thereafter, when amounts aretransferred to Development assets and when indicators exist.

Š Development assets:

Š The Company’s net book value of property, plant and equipment excluding E&E as at December 31,2009 will be the opening cost of Development assets at January 1, 2010.

Š A gain or loss must be calculated upon the sale, swap or transfer of assets.

Š Depletion and Depreciation will be calculated at the “Component” level.

Š Impairment will be assessed at the CGU level. Impairment of Development assets occurs when the netbook value exceeds the recoverable amount; the recoverable amount will likely be calculated using adiscounted cash flow model. The excess of the carrying amount over the recoverable amount isexpensed during the period of impairment. Development assets will be assessed for impairment atJanuary 1, 2010, and thereafter when indicators exist.

IFRS 1 Amendment

On July 23, 2009, the International Accounting Standards Board (“IASB”) issued amendments to IFRS 1, “First-time Adoption of International Financial Reporting Standards” (“IFRS 1”) that greatly reduced the amount of effortrequired upon transition to IFRS for entities, such as Tourmaline, that have historically applied the full-cost method ofaccounting. Under the amendment, Canadian GAAP full cost pools are allocated to smaller units of account at thetransition date of January 1, 2010 based on either reserve volumes or values and, currently, Tourmaline intends to relyon this exemption and perform this allocation based on reserve values.

There are still a number of significant differences associated with accounting for capital assets under IFRS versusCanadian GAAP which will impact the Company. Under Canadian GAAP’s full-cost accounting, expenditures relatedto oil and gas assets are aggregated on a country-by-country basis for depletion and impairment testing purposes.Under IFRS, the unit of account for both depletion and impairment testing is significantly smaller and accordingly,non-cash impairments are more likely under IFRS than under Canadian GAAP full-cost accounting.

Tourmaline’s current accounting systems and processes are capable of accounting for capital assets at the moredetailed level required under IFRS.

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Deferred Income Taxes

Tourmaline has been closely monitoring the progress associated with the IASB’s exposure draft to replaceInternational Accounting Standard (“IAS”) 12 “Income Taxes.” In October 2009, the IASB decided it would notproceed with the exposure draft and instead would consider a limited scope project to amend IAS 12. Accordingly,Tourmaline is evaluating the differences between the current version of IAS 12 and the relevant Canadian GAAPrequirements.

Asset Retirement Obligations

A major difference between current Canadian standards and IFRS appears to be the discount rate used to measurethe asset retirement obligation. Under current Canadian standards a credit adjusted risk free rate is used in calculatingthe provision. Under IFRS, a risk free rate should be used when the expected cash flows are risked. Within theindustry, there has been a debate as to whether there should be a risk component applied to conventional propertyestimated cash outflows used in determining the provision. The Company is monitoring this matter and will bedeciding which rate is the most appropriate in its circumstances. A lower discount rate will increase the provision ontransition to IFRS with a corresponding charge to retained earnings or deficit.

Business Combination

The Company did not elect to early adopt the newly issued Handbook section 1582, which has been aligned withIFRS 3, therefore there will be two major differences in the purchase price allocations of business combinations thathave occurred during 2010 upon conversion to IFRS. The first is that the consideration paid in the contract between thedeal close and the reporting date, if it involved financial instruments other than cash, must be measured at fair value.The second difference will be that transaction costs incurred by the Company that are directly related to the acquisitionmust be expensed in the period incurred, whereas under current GAAP they have been capitalized as part of the cost ofthe acquisition. The full impact of these changes has not yet been quantified.

Tourmaline also intends to apply the IFRS 1 exemption to value business combinations at the amounts determinedunder Canadian GAAP, rather than applying the IFRS rules retrospectively.

Issues Associated with the Initial Adoption of IFRS

Aside from the exemptions discussed above, Tourmaline has not yet ultimately concluded what other availableexemptions it will take upon transition to IFRS.

Tourmaline has conducted a review of its accounting systems and processes and, as a result of a various upgradesthat have been completed over recent years, the Company’s current systems and processes will accommodate thetransition to IFRS.

Tourmaline has established internal controls associated with the IFRS transition which include approvals atvarious stages of the project and the Company continues to work closely with its advising public accounting firm inrelation to the IFRS conversion.

Application of Critical Accounting Estimates

The Company’s consolidated financial statements included in this prospectus have been prepared in accordancewith Canadian GAAP. A summary of significant accounting policies is presented in Note 1 to the Company’sDecember 31, 2009 consolidated financial statements. Certain accounting policies require that management makeappropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts ofassets, liabilities, revenues and expenses. Management reviews its estimates on a regular basis. The emergence of newinformation and changed circumstances may result in actual results or changes to estimated amounts that differmaterially from current estimates. The following discussion identifies the critical accounting policies and practices ofthe Company and helps assess the likelihood of materially different results being reported.

Reserves

Under the NI 51-101, “Proved” reserves are defined as those reserves that can be estimated with a high degree ofcertainty to be recoverable. The level of certainty should result in at least 90% probability that the quantities actually

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recovered will equal or exceed the estimated Proved reserves. It does not mean that there is a 90% probability that theProved reserves will be recovered; it means there must be at least 90% probability that the given amount or more willbe recovered.

“Proved plus Probable” reserves are the most likely case and are based on a 50% certainty that they will equal orexceed the reserves estimated.

These oil and gas reserve estimates are made using all available geological and reservoir data, as well as historicalproduction data. All of the Company’s reserves were evaluated and reported on by independent qualified reservesevaluators. However, revisions can occur as a result of various factors, including actual reservoir performance, changesin price and cost forecasts or a change in the Company’s plans. Reserve changes will impact the financial results asreserves are used in the calculation of depletion and are used to assess whether asset impairment occurs. Reservechanges also affect other non-GAAP measurements such as finding and development costs, recycle ratios and net assetvalue calculations.

Depletion and Depreciation

The Company follows the full-cost method of accounting for oil and natural gas properties. Under this method, allcosts related to the acquisition of, exploration for and development of oil and natural gas reserves are capitalizedwhether successful or not. Depletion of the capitalized oil and natural gas properties and depreciation of productionequipment, which includes estimated future development costs less estimated salvage values, are calculated using theunit-of-production method, based on production volumes in relation to estimated proved reserves.

An increase in estimated proved reserves would result in a reduction in depletion expense. A decrease in estimatedfuture development costs would also result in a reduction in depletion expense.

Unproved Properties

The cost of acquisition and evaluation of unproved properties are initially excluded from depletion calculation. Animpairment test is performed on these assets to determine whether the carrying value exceeds the fair value. Anyexcess in carrying value over fair value is an impairment. When proved reserves are assigned or a property isconsidered to be impaired, the cost of the property or the amount of the impairment will be added to the capitalizedcosts for the calculation of depletion.

Ceiling Test

The ceiling test is a cost recovery test intended to identify and measure potential impairment of the value of assetsrelative to the cost of those assets as carried on the Company’s balance sheet. An impairment loss is recorded if thesum of the undiscounted cash flows (assuming certain commodity prices, operating costs, royalty rates and otherdeductions) expected from the production of the proved reserves and the lower of cost and market of unprovedproperties does not exceed the values of the petroleum and natural gas assets as carried in the Company’s balancesheet. An impairment loss is recognized to the extent that the carrying value exceeds the sum of the discounted cashflows expected from the production of proved and probable reserves and the lower of cost and market of unprovedproperties. The cash flows are estimated using the future product prices and costs and are discounted using the risk-free rate. By their nature, these estimates are subject to measurement uncertainty, and the impact on the financialstatements could be material. Any impairment as a result of this ceiling test will be charged to operations as additionaldepletion and depreciation expense.

A ceiling test was performed quarterly by the Company, and at each testing period, the Company had sufficientvalue of the Company’s proved and probable reserves under the formula to cover the value of the petroleum andnatural gas assets as carried on the Company’s balance sheet.

Asset Retirement Obligations

The Company records a liability for the fair value of legal obligations associated with the retirement of petroleumand natural gas assets. The liability is equal to the discounted fair value of the obligation in the period in which theasset is recorded with an equal offset to the carrying amount of the asset. The liability then accretes to its fair valuewith the passage of time and the accretion is recognized as an expense in the consolidated financial statements. The

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total amount of the asset retirement obligation is an estimate based on the Company’s net ownership interest in allwells and facilities, the estimated costs to abandon and reclaim the wells and facilities and the estimated timing of thecosts to be incurred in future periods. The total amount of the estimated cash flows required to settle the assetretirement obligation, the timing of those cash flows and the discount rate used to calculate the present value of thosecash flows are all estimates subject to measurement uncertainty. Any change in these estimates would impact the assetretirement liability and the accretion expense.

Income Taxes

The determination of income and other tax liabilities requires interpretation of complex laws and regulations. Alltax filings are subject to audit and potential reassessment after the lapse of considerable time. In addition, the Companyestimates when its temporary differences are expected to reverse and recognizes its tax assets and liabilities based onthe legislated tax rate in those periods. Accordingly, the actual income tax liability may differ significantly from thatestimated and recorded by management.


The Company applies the fair value method for valuing stock Option grants. This method requires the Companyto make estimates of expected stock volatility, the expected hold period prior to exercising Options, expectedforfeitures of Options and expected dividends to be declared by the Company. The calculation of the fair value ofstock-based compensation is not adjusted for the value actually received by the optionees. The stock-basedcompensation expense will not represent the actual fair value received by the optionees as the fair value is estimated atthe time of grant and is not adjusted. Due to the time period and the number of estimates involved, it is likely that theactual value of the options will differ from what has been recorded in the Company’s financial statements.

Other Estimates

The accrual method of accounting requires management to incorporate certain estimates, including estimates ofrevenues, royalties and operating costs as at a specific reporting date, but for which actual revenues and costs have notyet been received. In addition, estimates are made on capital projects that are in progress or recently completed whereactual costs have not been received by the reporting date. The Company obtains the estimates from the individuals withthe most knowledge of the activity and from all project documentation received. The estimates are reviewed forreasonableness and compared to past performance to assess the reliability of the estimates. Past estimates are comparedto actual results in order to make informed decisions on future estimates.

Business Risks and Uncertainties

Tourmaline monitors and complies with current government regulations that affect its activities, althoughoperations may be adversely affected by changes in government policy, regulations or taxation. In addition,Tourmaline maintains a level of liability, property and business interruption insurance which is believed to be adequatefor Tourmaline’s size and activities, but the Company is unable to obtain insurance to cover all risks within thebusiness or in amounts to cover all possible claims.

Impact of New Environmental Regulations

Environmental legislation, including the Kyoto Accord, the federal government’s EcoACTION plan and Alberta’sBill 3 – Climate Change and Emissions Management Amendment Act, is evolving in a manner expected to result instricter standards and enforcement, larger fines and liability and potentially increased capital expenditures andoperating costs. Given the evolving nature of the debate related to climate change and the resulting requirements, it isnot possible to determine the operational or financial impact of those requirements on Tourmaline.

Accounting Policy Updates

Effective December 31, 2009, the Company adopted the CICA amended Section 3862, “Financial Instruments –Disclosures”, to include additional disclosure requirements about fair value measurement for financial instruments andliquidity risk disclosures. These amendments require a three level hierarchy that reflects the significance of the inputsused in making the fair value measurements. Fair values of assets and liabilities included in Level 1 are determined by

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reference to quoted prices in active markets for identical assets and liabilities. Assets and liabilities in Level 2 includevaluations using inputs other than quoted prices for which all significant outputs are observable, either directly orindirectly. Level 3 valuations are based on inputs that are unobservable and significant to the overall fair valuemeasurement. The adoption of this policy did not impact the measurement of the amounts reported in the Company’sfinancial statements as they primarily relate to disclosure.

Future Accounting Changes

Business Combinations

In December 2008, the CICA issued Section 1582, “Business Combinations”. This section is effectiveJanuary 1, 2011 and applies prospectively to business combinations for which the acquisition date is on or after the firstannual reporting period beginning on or after January 1, 2011 for the Company. Early adoption is permitted. Thissection replaces Section 1581, Business Combinations, and harmonizes the Canadian standards with IFRS. Tourmalinehas opted against early adoption of this standard.

Consolidated Financial Statements and Non-Controlling Interest

In 2009, Section 1601 and Section 1602 were issued, which replace the existing guidance under Section 1600,“Consolidated Financial Statements”. These standards provide guidance for preparing consolidated financial statementsand for accounting for non-controlling interest in a subsidiary subsequent to a business combination. These standardsare effective for business combinations occurring on or after January 1, 2011, with early adoption permitted.Tourmaline has opted against early adoption of this standard.

DIVIDENDS

The Company has never declared or paid any cash dividends on the Common Shares. The Company currentlyintends to retain future earnings, if any, for future operations, expansion and debt repayment. Any decision to declareand pay dividends will be made at the discretion of the Board of Directors and will depend on, among other things, theCompany’s results of operations, current and anticipated cash requirements and surplus, financial condition,contractual restrictions and financing agreement covenants, solvency tests imposed by corporate law and other factorsthat the Board may deem relevant.

In addition to the foregoing, the Company’s ability to pay dividends now or in the future may be limited bycovenants contained in the agreements governing any indebtedness that the Company has incurred or may incur in thefuture including the terms of the Credit Facilities. The Tourmaline Credit Facility prohibits Tourmaline from declaringor paying any dividends (excluding stock dividends) to any of its shareholders or returning any capital (including byway of dividend) to any of its shareholders.

DESCRIPTION OF SHARE CAPITAL

The authorized share capital of Tourmaline consists of an unlimited number of Common Shares and an unlimitednumber of First Preferred Shares and an unlimited number of Second Preferred Shares. As of the date hereof there are123,841,060 Common Shares issued and outstanding and an additional 11,772,000 Common Shares are reserved forissuance upon the exercise of outstanding Options. No First Preferred Shares or Second Preferred Shares are currentlyissued and outstanding.

The following is a summary of the rights, privileges, restrictions and conditions attaching to the shares inTourmaline’s share capital.

Common Shares

Tourmaline is authorized to issue an unlimited number of Common Shares without nominal or par value. Holdersof Common Shares are entitled to one vote per share at meetings of shareholders of Tourmaline. Subject to the rights ofthe holders of First Preferred Shares and Second Preferred Shares and any other shares having priority over theCommon Shares, holders of Common Shares are entitled to dividends if, as and when declared by the Board ofDirectors and upon liquidation, dissolution or winding-up to receive the remaining property of Tourmaline.

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First Preferred Shares

The First Preferred Shares are issuable in series and will have such rights, restrictions, conditions and limitationsas the Board of Directors may from time to time determine. No First Preferred Shares have been issued.

Tourmaline is authorized to issue an unlimited number of First Preferred Shares without nominal or par value.Holders of First Preferred Shares are entitled to receive dividends if, as and when declared by the Board of Directors,in priority to holders of Common Shares and Second Preferred Shares. In the event of a liquidation, dissolution orwinding-up of Tourmaline, holders of the First Preferred Shares are entitled to receive a rateable share of alldistributions made in priority to the holders of the Common Shares and Second Preferred Shares.

Second Preferred Shares

The Second Preferred Shares are issuable in series and will have such rights, restrictions, conditions andlimitations as the Board of Directors may from time to time determine. No Second Preferred Shares have been issued.

Tourmaline is authorized to issue an unlimited number of Second Preferred Shares without nominal or par value.Holders of Second Preferred Shares are entitled to receive dividends if, as and when declared by the Board of Directorssubject to the preference of First Preferred Shares but in priority to holders of Common Shares. In the event of aliquidation, dissolution or winding-up of Tourmaline, holders of the Second Preferred Shares are entitled to receive arateable share of all distributions made, subject to the preference of holders of First Preferred Shares but in priority toholders of Common Shares.

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CONSOLIDATED CAPITALIZATION

The following table sets forth the consolidated share and loan capitalization of the Company as atSeptember 30, 2010 and the pro forma consolidated share and loan capitalization of the Company as at September 30,2010, after giving effect to the Offering, the Concurrent Private Placement and the Deep Basin West Acquisition. Otherthan as described below, there has not been any material change in the share and loan capital of the Company, on aconsolidated basis, since September 30, 2010. This table must be read in conjunction with the Company’s“Management’s Discussion and Analysis” and the Company’s consolidated historical financial statements andaccompanying notes contained in this prospectus.

($000, except per share amounts)Description

SecuritiesAuthorized As at September 30, 2010

As at September 30, 2010,after giving effect to the

Offering and theConcurrent Private

Placement(2)

As at September 30, 2010,after giving effect tothe Offering, the

Concurrent PrivatePlacement and the

Deep BasinWest Acquisition(2)(4)

(unaudited) (unaudited) (unaudited)

Bank Debt – Credit Facilities(1) . . . . . N/A $41,186 $nil $nilCommon Shares(2)(3) . . . . . . . . . . . . . Unlimited $1,270,156

(123,841,060 shares)$1,486,669

(134,691,060 shares)$1,486,669

(134,691,060 shares)

Notes:(1) The Company has a $100 million revolving/non-revolving term credit facility (the “Tourmaline Revolving Facility”) and a $15 million

operating credit facility (the “Tourmaline Operating Facility”) (the Tourmaline Revolving Facility and the Tourmaline Operating Facility aretogether, the “Tourmaline Credit Facility”) with two Canadian chartered banks. As at September 30, 2010, $34.5 million had been drawn onthe Tourmaline Revolving Facility and $2.8 million had been drawn on the Tourmaline Operating Facility. Under the terms of the TourmalineCredit Facility, Tourmaline is required to maintain certain financial covenants on a consolidated basis. As at the date hereof, Tourmaline is incompliance with all of its covenants. The Tourmaline Credit Facility currently bears interest on a variable grid ranging from 225 to 375 basispoints over the prevailing bankers’ acceptance rate. Security for the Tourmaline Credit Facility includes a general security agreement and a $500million demand loan debenture secured by a first floating charge over all of the Company’s assets. The Tourmaline Credit Facility is subject torenewal on July 31, 2011 and may be extended for a further 364-day period at the request of the Company and subject to approval by thelenders. Exshaw has a $5 million revolving/non-revolving term credit facility (the “ Exshaw Revolving Facility”) and a $5 million operatingcredit facility (the “Exshaw Operating Facility”) (the Exshaw Revolving Facility and the Exshaw Operating Facility are together, the “ExshawCredit Facility”) with two Canadian chartered banks. As at September 30, 2010, $nil had been drawn on the Exshaw Revolving Facility and$3.9 million had been drawn on the Exshaw Operating Facility. Under the terms of the Exshaw Credit Facility, Exshaw is required to maintaincertain financial covenants. As at the date hereof, Exshaw is in compliance with all of its covenants. The Exshaw Credit Facility currently bearsinterest on a variable grid ranging from 225 to 375 basis points over the prevailing bankers’ acceptance rate. Security for the Exshaw CreditFacility includes a general security agreement and a $200 million demand loan debenture secured by a first floating charge over all of Exshaw’sassets. The Exshaw Credit Facility is subject to renewal on July 31, 2011 and may be extended for a further 364-day period at the request ofExshaw and subject to approval by the lenders. As at September 30, 2010, $41.2 million was drawn under the Credit Facilities and as atNovember 15, 2010, approximately $113.7 million was drawn under the Credit Facilities.

(2) Does not include any Common Shares issuable upon exercise of the Over-Allotment Option. If the Over-Allotment Option is exercised in full,there will be an aggregate of 136,191,060 Common Shares outstanding as at September 30, 2010 after giving effect to the completion of theOffering, the Concurrent Private Placement and the issue and sale of 1,500,000 Common Shares pursuant to the exercise of the Over-AllotmentOption.

(3) As at the date hereof, a total of 11,772,000 Common Shares are reserved for issuance on exercise of outstanding Options. See “Options toPurchase Common Shares” and “Executive Compensation”.

(4) As at September 30, 2010, if the Over-Allotment Option is exercised in full, the Company’s long-term debt under the Credit Facilities would be$nil. See “Recent Developments – Deep Basin West Acquisition”.

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OPTIONS TO PURCHASE COMMON SHARES

The following table sets forth certain information in respect of Options to purchase Common Shares that areoutstanding as of the date hereof and that are anticipated to be outstanding at Closing. See also “ExecutiveCompensation – Long-Term Incentive Plans – Option Plan”.

Group (Number in Group)

Common SharesUnder Option

(#)

Exercise Price perCommon Share(1)

($) Expiration Date

Current and former executive officers of the Company(“Company Executives”) (8) . . . . . . . . . . . . . . . . . . . . . . . . 1,550,000 7.00 November 15, 2013

825,000 10.00 June 1, 2014625,000 15.00 December 1, 2014550,000 18.35 September 15, 2015

Current and former directors of the company, excludingCompany Executives (“Company Directors”) (6) . . . . . . . 500,000 7.00 November 15, 2013

250,000 10.00 June 1, 2014195,000 18.35 September 15, 2015

Current and former employees of the Company . . . . . . . . . . . . 1,600,000 7.00 November 15, 2013345,000 8.00 February 15, 2014245,000 10.00 May 15, 2014480,000 10.00 June 1, 2014240,000 10.00 June 15, 2014385,000 12.00 September 15, 2014685,000 15.00 November 1, 2014860,000 15.00 December 1, 2014490,000 15.00 January 1, 2015170,000 16.68 February 15, 2015330,000 18.00 April 1, 201595,000 18.00 May 1, 2015

162,000 18.20 July 1, 20151,005,000 18.35 September 15, 2015

Consultants to the Company and its subsidiaries . . . . . . . . . . . 90,000 18.20 July 1, 201595,000 18.35 September 15, 2015

Note:(1) The market value of the Common Shares underlying these Options on both the date of grant and the date of this prospectus is not reasonably

ascertainable given that the Common Shares are not and have never been publicly listed or traded.

PRIOR SALES

The following tables provide details regarding all Common Shares and all securities that are convertible intoCommon Shares that have been issued by the Company during the 12-month period prior to the date of this prospectus.

Common Shares Issued During the Last 12 Months

Date of Issuance Number of Common Shares Issue Price per Common Share

August 12, 2010(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,150,000 $22.00June 1, 2010(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,500,000 $18.00March 19, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,500,000 $18.00March 19, 2010(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,450,000 $21.60February 15, 2010(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20,000 $ 8.00January 14, 2010(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,411,669 $15.00November 10, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11,793,624 $15.00November 10, 2009(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,750,000 $18.00November 10, 2009(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,837,522 $12.00November 10, 2009(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,875,181 $12.00

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Options Granted During the Last 12 Months

Date of Issuance Number of Options Exercise Price of Options

September 15, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,845,000 $18.35July 1, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 252,000 $18.20May 1, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95,000 $18.00April 1, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 330,000 $18.00February 15, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 170,000 $16.68January 1, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 490,000 $15.00December 1, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,485,000 $15.00November 1, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 685,000 $15.00

Notes:(1) Issued as Flow-Through Shares.(2) Common Shares issued as consideration for acquisitions.(3) Issued on exercise of Options.

ESCROWED COMMON SHARES

The following table sets forth, as of the date of this prospectus, the number of securities of each class of securitiesof Tourmaline held, to the knowledge of Tourmaline, in escrow or that is subject to a contractual restriction on transferand the percentage that number represents of the outstanding securities of that class:

Designation of ClassNumber of Securities Held

in Escrow(1)(2) Percentage of Class

Common Shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28,500,000 23%

Notes:(1) Shares held in escrow pursuant to an escrow agreement dated October, 27, 2008 among CIBC Mellon Trust Company (now Canadian Stock

Transfer Company, Inc.) (as escrow agent), Tourmaline and certain shareholders of Tourmaline (the “Escrow Agreement”).(2) Pursuant to the Escrow Agreement, all of the escrowed Common Shares will be released from escrow on Closing, upon the listing and posting

for trading of the Common Shares on an “Exchange” as defined in the Escrow Agreement, which includes the TSX.

PRINCIPAL SHAREHOLDERS

To the knowledge of Tourmaline, and based on existing information, as at the date hereof, there are no personswho beneficially own, or exercise control or direction over, directly or indirectly, over more than 10% of the CommonShares.

USE OF PROCEEDS

Proceeds

The Company expects to receive net proceeds from the Offering of approximately $194,700,000 (after deductingthe Underwriters’ Commission in the amount of $11,550,000 and the expenses of the Offering, estimated to be$3,750,000) and gross proceeds from the Concurrent Private Placement of $17,850,000. The Company will receive netproceeds from the Offering and gross proceeds from the Concurrent Private Placement of $242,317,500 if the Over-Allotment Option is exercised in full.

Principal Purposes

Based upon management’s current intentions, the Company expects to use the net proceeds of the Offering andthe gross proceeds from the Concurrent Private Placement to fund a portion of its budgeted $425 million 2011 capitalexploration and development program and, specifically, for the principal purposes of: (i) development and explorationdrilling and well completions; (ii) expansion and equipping of facilities and pipelines; and (iii) acquisition of new land,seismic and geological data. Until required for purpose of the Company’s 2011 capital explanation and developmentprogram, the net proceeds from the Offering and gross proceeds from the Concurrent Private Placement will be appliedto temporarily reduce outstanding indebtedness under the Tourmaline Revolving Facility which will subsequently beredrawn and applied to fund the 2011 capital exploration and development program.

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A summary of Tourmaline’s 2011 capital exploration and development budget is set forth below.

CapitalExpenditure

(MM$)

Development drilling and well completionsAlberta Deep Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 180.5Greater Peace River High . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66.0

246.5Exploration drilling and well completions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24.0Expansion and equipping of facilities and pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100.0Acquisition of new land and seismic and geological data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54.5

425.0

The Company expects to fund the remainder of the 2011 capital exploration and development program from cashgenerated from its operations and draws under the Credit Facilities. The Company’s 2011 capital exploration anddevelopment program is described under the heading “Description of the Business – 2011 Capital Expenditure andDevelopment Program”. Due to the nature of the oil and gas industry, budgets are regularly reviewed with respect tothe success of the expenditures and other opportunities which become available to the Company. Accordingly, while itis currently intended by management that the net proceeds of the Offering will be expended as set forth above, actualexpenditures may differ from these amounts and allocations. Pending utilization of the net proceeds of the Offering, thefunds will be deposited in bank accounts at Canadian chartered banks or be invested in short-term bank securities orshort-term Canadian or U.S. government securities pursuant to the Company’s investment policy. The Board ofDirectors may amend the Company’s investment policy from time to time at its discretion.

If the Company is unable to complete the entire 2011 capital exploration and development program in 2011 asplanned, the balance of the program will be deferred to 2012 and the Company’s anticipated growth in its futureproduction, cash flows and reserves would be delayed.

The Company’s current indebtedness under the Credit Facilities has been incurred in the normal course ofbusiness and operations and in connection with previous capital and other expenditures made by the Company. If theDeep Basin West Acquisition is completed, the Company will incur additional indebtedness under the Credit Facilities.See “Recent Developments – Deep Basin West Acquisition”, “Consolidated Capitalization”, “Plan of Distribution” and“Relationship Between the Company and Certain of the Underwriters”.

Business Objectives and Milestones

The principal purposes for the net proceeds from the Offering as described above are consistent with theCompany’s business objectives and strategic goals relating to the exploration for and development of oil and naturalgas reserves. In particular, the Company’s objectives in using the net proceeds from the Offering are to grow its reservebase and expand production on its current properties, as well as to seek opportunities to acquire new properties thatmay increase shareholder value. The success of the Company in meeting its objectives will depend on the success of itsdrilling program and the availability of accretive opportunities, which cannot be determined in advance.

By its nature, the oil and gas business is dynamic and requires constant review, analysis and determination ofprudent allocations of capital spending. Depending on the degree of success achieved from the Company’s plannedactivities, management will assess and may establish additional objectives and milestones for the Company to meet.

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DIRECTORS AND EXECUTIVE OFFICERS

Summary Information

The following table sets forth certain summary information in respect of the Company’s directors and executiveofficers as at the date of this prospectus.

Name, Province and Country ofResidence Position Held

Principal Occupationfor the Last Five Years Director Since

MICHAEL L. ROSE . . . . . . . . . . . . . . . . . .Alberta, Canada

Chairman, President and ChiefExecutive Officer

Chairman, President and ChiefExecutive Officer of Tourmaline sinceAugust 2008. Prior thereto, Chairman,President and Chief Executive Officerof Duvernay, an oil and gas company.

August 6, 2008

WILLIAM D. ARMSTRONG(4)(5) . . . . . . . . .Colorado, United States

Director President and Chief Executive Officerof Armstrong Oil & Gas Inc., an oiland gas exploration and productioncompany.

October 27, 2008

ROBERT W. BLAKELY(1)(2)(3)(5) . . . . . . . . .Ontario, Canada

Director President of Likrilyn CapitalCorporation, an investmentmanagement company.

October 27, 2008

KEVIN KEENAN(1)(2)(3)(4) . . . . . . . . . . . . . .Alberta, Canada

Director Independent businessman sinceNovember 2009. Prior thereto, VicePresident, Operations and ChiefOperating Officer of Exshaw. Priorthereto, President of Manor HouseVenture Partners Inc.

October 27, 2008

PHILLIP A. LAMOREAUX(1)(2)(3)(4)(5) . . . . . .California, United States

Director Managing Member of LamoreauxCapital Management LLC, aninvestment management company.

September 9, 2010

CLAYTON H. RIDDELL . . . . . . . . . . . . . . .Alberta, Canada

Director Chairman and Chief Executive Officerof Paramount Resources Ltd., an oiland gas company.

October 27, 2008

BRIAN G. ROBINSON . . . . . . . . . . . . . . . .Alberta, Canada

Director and Vice President,Finance and Chief FinancialOfficer

Director and Vice President, Financeand Chief Financial Officer ofTourmaline since August 2008. Priorthereto, Vice President, Finance andChief Financial Officer of Duvernay.

October 27, 2008

ROBERT N. YURKOVICH(6) . . . . . . . . . . . .Alberta, Canada

Director and Executive VicePresident, Exploration

Director and Executive Vice President,Exploration of Tourmaline sinceOctober 2008. Prior thereto, VicePresident, Exploration of Duvernay.

October 27, 2008

STANLEY NOWEK . . . . . . . . . . . . . . . . . . .Alberta, Canada

Vice President, Operations andChief Operating Officer

Vice President, Operations and ChiefOperating Officer of Tourmaline sinceOctober 2008. Prior thereto, VicePresident, Operations and ChiefOperating Officer of Duvernay.

N/A

RONALD J. HILL . . . . . . . . . . . . . . . . . . . .Alberta, Canada

Vice President, Exploration Vice President, Exploration ofTourmaline since November 2009.Prior thereto, Senior Geologist atTourmaline and Duvernay.

N/A

DREW E. TUMBACH . . . . . . . . . . . . . . . . .Alberta, Canada

Vice President, Land and Contracts Vice President, Land and Contracts ofTourmaline since October 2008. Priorthereto, Vice President, Land andContracts of Duvernay.

N/A

W. SCOTT KIRKER . . . . . . . . . . . . . . . . . .Alberta, Canada

Secretary and General Counsel Secretary and General Counsel ofTourmaline since August 2008. Priorthereto, Manager Corporate Affairs ofDuvernay.

N/A

Notes:(1) Member of the Audit Committee. Mr. Robert W. Blakely is the Chairman of the Audit Committee.

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(2) Member of the Compensation Committee. Mr. Robert W. Blakely is the Chairman of the Compensation Committee.(3) Member of the Corporate Governance Committee. Mr. Phillip A. Lamoreaux is the Chairman of the Corporate Governance Committee.(4) Member of the Reserves, Safety and Environmental Committee. Mr. William D. Armstrong is the Chairman of the Reserves, Safety and

Environmental Committee.(5) Independent director.(6) Mr. Yurkovich is part time in his capacity as Executive Vice President, Exploration.

All of the Company’s directors’ terms of office will expire at the earliest of their resignation, the close of the nextannual shareholder meeting called for the election of directors, or on such other date as they may be removed accordingto the ABCA. Each director will devote the amount of time as is required to fulfill his obligations to the Company. TheCompany’s officers are appointed by and serve at the discretion of the Board of Directors.

Directors and Executive Officers – Biographies

The following are brief profiles of the directors and executive officers of the Company, including a description ofeach individual’s principal occupation within the past five years.

Michael L. Rose – Chairman, President and Chief Executive Officer

Michael L. Rose has more than 30 years of experience in the oil and natural gas industry. Mr. Rose founded andserved as President and Chief Executive Officer of Duvernay and Berkley. Prior to that, he was employed for 14 yearsat Shell Canada in various exploration and production positions and was Manager of Exploration and PetroleumEngineering Research at the time he departed to found Berkley in 1993. Mr. Rose holds a Bachelor of Science inGeology from Queen’s University.

William D. Armstrong – Director

William Armstrong has more than 30 years of experience in the oil and natural gas industry. Mr. Armstrong iscurrently the President and Chief Executive Officer of the Denver-based Armstrong Oil & Gas Inc., a private oil andgas exploration company. Mr. Armstrong holds a Bachelor of Science from Southern Methodist University, Dallas,Texas.

Robert W. Blakely – Director

Robert W. Blakely has more than 20 years of experience in corporate finance and is currently the President andChief Executive Officer of Likrilyn Capital Corporation (“Likrilyn”) and its Canadian and U.S. subsidiaries. Prior tofounding Likrilyn, Mr. Blakely was the President and Chief Executive Officer of Northern Rivers Capital Managementand prior to that practiced law and was a Managing Partner at Raymond and Honsberger. Mr. Blakely is a director ofThe Caring Foundation and is a Member of the Advisory Board at Northern Plains Investment Counsel. Mr. Blakelyhas been the Chairman of the Arts & Science Dean’s Council at Queen’s University. Mr. Blakely holds a Bachelor ofArts and a Bachelor of Law from Queen’s University.

Kevin Keenan – Director

Kevin J. Keenan has more than 26 years of experience in the oil and natural gas industry. Mr. Keenan is currentlyan independent businessman in Calgary, Alberta. Prior to that, he was Vice President, Operations and Chief OperatingOfficer of Exshaw and President of Manor Venture Partners. Mr. Keenan holds a Bachelor of Applied Science from theUniversity of Toronto.

Phillip A. Lamoreaux – Director

Phillip A. Lamoreaux has more than 40 years of experience in the financial investment industry and is themanaging member of Lamoreaux Capital Management, an investment firm focusing on innovative public and privateemerging growth companies. Mr. Lamoreaux has served as program chairman for the Financial Analysts FederationHigh Technology Conference and is currently a member of the CFA Society of San Francisco. Mr. Lamoreaux holds aBachelor of Arts in Economics, with minors in engineering and mathematics from Stanford University and an MBAfrom the Harvard Graduate School of Business.

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Clayton H. Riddell – Director

Clayton H. Riddell has more than 50 years of experience in the oil and natural gas industry. Mr. Riddell is theChief Executive Officer and Chairman at Paramount Resources Ltd. Mr. Riddell also serves as the Chairman ofPerpetual Energy Inc. and Trilogy Energy Trust. Mr. Riddell is a member of the Association of Professional Engineers,Geologists, and Geophysicists of Alberta (“APEGGA”), the Canadian Association of Petroleum Producers, theCanadian Society of Petroleum Geologists, the American Association of Petroleum Geologists and the CanadianGeoScience Council. Mr. Riddell holds a Bachelor of Science, with honours, in Geology from the University ofManitoba.

Brian G. Robinson – Director and Vice President, Finance and Chief Financial Officer

Brian G. Robinson has 30 years experience in the oil and natural gas industry. Mr. Robinson also served as VicePresident, Finance and Chief Financial Officer for Duvernay and Berkley. Prior to these appointments, he held variousfinance and accounting positions in public oil and gas companies. Mr. Robinson holds a Bachelor of Commerce degreefrom the University of Calgary and is a Chartered Accountant.

Robert N. Yurkovich – Director and Executive Vice President, Exploration

Robert N. Yurkovich has over 29 years of experience in the oil and natural gas industry. Mr. Yurkovichpreviously served as Vice President, Exploration of Duvernay and as Executive Vice President, Exploration of Berkley.Mr. Yurkovich also served as a director of both of Duvernay and Berkley. In 2003, he was awarded theStanley K. Slipper Award by the Canadian Society of Petroleum Geologists for outstanding contributions to oil and gasexploration in Canada. Mr. Yurkovich is a member of APEGGA. Mr. Yurkovich holds a Bachelor of Science in EarthScience, with honours, from the University of Waterloo.

Stanley Nowek – Vice President, Operations and Chief Operating Officer

Stanley M. Nowek has more than 30 years experience in the oil and natural gas industry. Prior to joiningTourmaline, he was Vice President, Operations and Chief Operating Officer of Duvernay and Manager, Engineering ofBerkley. He is a member of APEGGA and the Association of Professional Engineers and Geoscientists of B.C.Mr. Nowek holds a B.Sc. in Chemical Engineering from the University of Alberta.

Ronald J. Hill – Vice President, Exploration

Ronald J. Hill has 30 years experience working in the oil and natural gas industry, with an emphasis on the playgeology of the WCSB. Mr. Hill began his professional career at Petro-Canada; rising to the position of ExplorationTeam Leader for NEBC. For the majority of the last 15 years, he has worked at Berkley, Duvernay and nowTourmaline with increasing roles and responsibilities. Mr. Hill holds a Bachelor of Science, with honours, in Geology,graduating in 1980 from the University of Western Ontario.

Drew E. Tumbach – Vice President, Land and Contracts

Drew E. Tumbach has more than 25 years of experience in the oil and gas industry. Mr. Tumbach was VicePresident, Land and Contracts at Duvernay and prior to that, was Vice President, Land at Anadarko Petroleum Corp.,following his tenure at Berkley as Vice President, Land and Contracts. Mr. Tumbach holds a Bachelor of Commercedegree from the University of Calgary and is a member of the Canadian Association of Petroleum Landmen.

W. Scott Kirker – Secretary and General Counsel

W. Scott Kirker has over 29 years of legal experience. Prior to joining Tourmaline, Mr. Kirker served as Managerof Corporate Affairs at Duvernay. Mr. Kirker has held various legal positions in private corporations and teachingpositions at the University of Calgary Haskayne School of Business. Mr. Kirker is a member of the Law Society ofAlberta and holds a Bachelor of Arts and Masters of Science degree from the University of Calgary and a Bachelor ofLaw from the University of Alberta.

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Committees of the Board of Directors

See Appendix “A” and “B” attached hereto for a description of the roles and responsibilities of each of thecommittees of the Board.

Share Ownership by Directors and Officers

As a group, the Company’s officers and directors beneficially own or exercise control or direction over, directly orindirectly, 32,032,852 Common Shares representing approximately 26% of the issued and outstanding Common Sharesprior to giving effect to the Offering. The Company has also been advised that certain of the Company’s officers anddirectors intend to acquire up to 135,000 Common Shares pursuant to the Offering and the Company has entered intoagreements with the Private Placees providing for the issue of 850,000 Common Shares pursuant to the ConcurrentPrivate Placement, which, together with the officers’ and directors’ existing holdings, will represent in the aggregateapproximately 25% of the issued and outstanding Common Shares of the Company following completion of theOffering and the Concurrent Private Placement. See “Concurrent Private Placement”.

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

Cease Trade Orders

To the knowledge of the Company, except as described below, no director or executive officer of the Company(nor any personal holding company of any of such persons) is, as of the date of this prospectus, or was within 10 yearsbefore the date of this prospectus, a director, chief executive officer or chief financial officer of any company(including the Company), that: (a) was subject to a cease trade order (including a management cease trade order), anorder similar to a cease trade order or an order that denied the relevant company access to any exemption undersecurities legislation, in each case that was in effect for a period of more than 30 consecutive days (collectively, an“Order”), that was issued while the director or executive officer was acting in the capacity as director, chief executiveofficer or chief financial officer; or (b) was subject to an Order that was issued after the director or executive officerceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurredwhile that person was acting in the capacity as director, chief executive officer or chief financial officer.

Mr. Clayton Riddell is a director and executive officer of Paramount Resources Ltd. (“Paramount”). From 1992to 2008, Paramount was the general partner of T.T.Y. Paramount Partnership No. 5 (“TTY”), a limited partnership,which was an unlisted reporting issuer in certain provinces of Canada. TTY was established in 1980 to conduct oil andgas exploration and development but had not carried on active operations since 1984 and had only nominal assets. Acease trade order against TTY was issued by the Autorité des marchés financiers in 1999 for failing to file the June 30,1998 interim financial statements in Québec. The cease trade order was revoked on April 9, 2008. TTY was dissolvedon July 21, 2008.

Bankruptcies

To the knowledge of the Company, no director or executive officer of the Company (nor any personal holdingcompany of any of such persons), or shareholder holding a sufficient number of securities of the Company to affectmaterially the control of the Company: (a) is, as of the date of this prospectus, or has been within the 10 years beforethe date of this prospectus, a director or executive officer of any company (including the Company) that, while thatperson was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt,made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted anyproceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed tohold its assets; or (b) has, within the 10 years before the date of this prospectus, become bankrupt, made a proposalunder any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings,arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assetsof the director, executive officer or shareholder.

Penalties or Sanctions

To the knowledge of the Company, no director or executive officer of the Company (nor any personal holdingcompany of any of such persons), or shareholder holding a sufficient number of securities of the Company to affectmaterially the control of the Company, has been subject to: (a) any penalties or sanctions imposed by a court relating tosecurities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securitiesregulatory authority; or (b) any other penalties or sanctions imposed by a court or regulatory body that would likely beconsidered important to a reasonable investor in making an investment decision.

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Conflicts of Interest

Certain officers and directors of the Company are also officers and/or directors of other entities engaged in the oiland gas business generally. As a result, situations may arise where the interest of such directors and officers conflictwith their interests as directors and officers of other companies. The resolution of such conflicts is governed byapplicable corporate laws, which require that directors act honestly, in good faith and with a view to the best interestsof the Company. Conflicts, if any, will be handled in a manner consistent with the procedures and remedies set forth inthe ABCA. The ABCA provides that in the event that a director has an interest in a contract or proposed contract oragreement, the director shall disclose his interest in such contract or agreement and shall refrain from voting on anymatter in respect of such contract or agreement unless otherwise provided by the ABCA.

EXECUTIVE COMPENSATION

The following describes the significant elements of the Company’s executive compensation program, withparticular emphasis on the process for determining compensation payable to the President and Chief Executive Officer(“CEO”), the Chief Financial Officer (“CFO”) and each of the three most highly compensated executive officers otherthan the CEO and the CFO (collectively, the “Named Executive Officers” or “NEOs”). The NEOs, based onanticipated 2010 compensation levels, are as follows:

Michael L. Rose, Chairman, President and CEO;Brian G. Robinson, Vice President, Finance and CFO;Ron Hill, Vice President, Exploration;Stan Nowek, Vice President, Operations and Chief Operating Officer; andDrew Tumbach, Vice President, Land and Contracts.

This description reflects the current expectations of management with respect to the Company’s executivecompensation program following the completion of the Offering. However, the Compensation Committee of the Board(the “Compensation Committee”) regularly reviews the Company’s executive compensation program and, ifdetermined appropriate, may make recommendations to the Board following Closing regarding changes to the programin light of relevant factors including the Company’s status as a public company.

Compensation Discussion and Analysis

General

Based on recommendations made by the Compensation Committee, the Board makes decisions regarding salaries,annual bonuses and equity incentive compensation for the executive officers, and approves corporate goals andobjectives relevant to the compensation of the CEO and the other executive officers. The Board solicits input from theCEO and the Compensation Committee regarding the performance of the Company’s other executive officers. TheBoard also administers the Option Plan with the assistance of the Compensation Committee.

Compensation Objectives and Principles

The Board recognizes that the Company’s success depends greatly on its ability to attract, retain and motivatesuperior performing employees at all levels, which can only occur if the Company has an appropriately structured andexecuted compensation program. The Company’s compensation policies are founded on the principle that executiveand employee compensation should be consistent with shareholders’ interests and the Company’s compensation plansare therefore intended to encourage decisions and actions that will result in the Company’s growth and in the creationof long-term shareholder value. In determining the compensation to be paid to NEOs, the Compensation Committeetakes into account corporate achievements, comparative market data and other relevant information supplied bymanagement of the Company.

Tourmaline’s compensation philosophy is based on three fundamental principles:

Š Strong link to business strategy – short and long-term corporate goals should be reflected in the overallexecutive compensation program;

Š Performance sensitive – compensation should be linked to the Company’s operating and market performanceand fluctuate with such performance; and

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Š Market relevant – the executive compensation program should provide market competitive pay in terms ofvalue and structure in order to retain existing employees who are performing according to their objectivesand to attract new recruits of the highest calibre.

The principal objectives of the Company’s executive compensation program are as follows:

Š to attract and retain qualified executive officers;

Š to have a compensation package that is competitive within the marketplace;

Š to align the executives’ interests with those of the Company’s shareholders and with the execution of theCompany’s business strategy; and

Š to reward the demonstration of both leadership and performance.

The Compensation Committee’s objective is to ensure that the compensation of the NEOs provides a competitivepackage that reflects both base expectations to attract and retain the appropriate level of individuals, as well as providea link between discretionary short and long-term incentives with short and long-term corporate goals. Thecompensation package is designed to reward performance based on the achievement of performance goals andobjectives and to be competitive with comparable companies in the market in which the Company competes for talent.

Components of Compensation

The following components currently comprise the compensation package for NEOs for the year endingDecember 31, 2010: base salary, annual short-term incentive and participation in the Company’s long-termcompensation plan, the Option Plan. The aggregate value of these components and related benefits, is used as a basisfor assessing the overall competitiveness of a NEO’s total compensation package. Salary increases, cash bonuses andstock–based compensation for the NEOs are reviewed and approved by the Compensation Committee.

Decisions concerning salary levels are made, in most respects, independently from decisions concerning otherelements of compensation, because the purpose of the base salary is to provide a fixed level of competitive pay thatreflects a NEO’s primary duties and responsibilities. It is the Board’s view, that decisions concerning the determinationof annual bonuses and long-term incentives also involve different factors and, therefore, most decisions in this regarddo not take into account the values of the other compensation components. As part of the compensation determinationprocess, the Board considers the proportion of each component relative to the total compensation amount and mayadjust each component as necessary.

Base Salary

The base salary is intended to provide a fixed level of compensation that reflects a NEO’s primary duties andresponsibilities. It also provides a foundation upon which incentive opportunities and benefit levels can be established.The Board considers a number of factors in the determination of base salaries for executive officers, includingTourmaline’s long-term interests, financial objectives, and overall performance generally and leadership ability, levelof responsibility, individual performance, years of relevant experience and salaries paid by comparable companiesmore specifically. Salaries of the NEOs and all other executive officers are reviewed annually based upon corporateand personal performance and on individual levels of responsibility.

Annual Short-Term Incentive Compensation

Annual short-term incentive compensation provides for annual cash awards, which are intended to motivate andreward NEOs for achieving and surpassing annual corporate and individual goals. Bonus awards for the NEOs, otherthan the CEO, are recommended by the CEO and reviewed and approved by the Compensation Committee. Bonusawards for the CEO are determined solely by the Compensation Committee. The ultimate granting of annual bonusamounts is at the discretion of the Board.

Long-Term Compensation

The Company’s long-term compensation program is currently comprised of the Option Plan, which is intended toencourage participants to focus on creating and improving the Company’s long-term financial success by providing

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participants an opportunity to increase their ownership interests in the Company. The purpose of the Option Plan is toalign shareholder and management interests. The Board believes that long-term incentive compensation plays anessential role in aligning the interests of executives with the goal of maximizing shareholder value and in attracting andretaining senior executives in the highly competitive market for oil and gas industry executives. Previous grants ofOptions are taken into account by the Board in granting additional Options.

Summary Compensation Table Expectations for 2010

Based on the information available at the date hereof, the following table sets out information concerning thecompensation anticipated to be paid by the Company to the Named Executive Officers during the year endedDecember 31, 2010.

Non-equity incentiveplan compensation ($)

Name and Principal Position Year SalaryOption-based

awards(1)

Annualincentive

plan

Long-termincentive

planAll other

compensationTotal

compensation

(Cdn$) (#) (Cdn$) (Cdn$)

Michael L. Rose(2) . . . . . . . . . . . . . . . 2010 — 300,000 — — — —Brian G. Robinson(2) . . . . . . . . . . . . . 2010 165,000 150,000 — — — 165,000Ronald Hill . . . . . . . . . . . . . . . . . . . . 2010 165,000 150,000 — — — 165,000Stan Nowek . . . . . . . . . . . . . . . . . . . . 2010 165,000 150,000 — — — 165,000Drew Tumbach . . . . . . . . . . . . . . . . . 2010 165,000 125,000 — — — 165,000

Notes:(1) The market value of the Common Shares underlying these Options on both the date of grant and the date of this prospectus is not reasonably

ascertainable given that the Common Shares are not and have never been publicly listed or traded.(2) Messrs. Rose and Robinson receive no additional compensation in their capacity as directors of the Company.

Termination and Change of Control Benefits

Tourmaline has not entered into or adopted any, contract, agreement, plan or arrangement that provides forpayments to a NEO at, following, or in connection with, any termination (whether voluntary, involuntary orconstructive), resignation, retirement, a change in control of Tourmaline or change in NEO’s responsibilities.

Director Compensation

Directors are reimbursed for expenses incurred in attending Board and committee meetings. Directors receive nocompensation for acting as directors of Tourmaline other than the grant of Options.

The following table sets forth information concerning the expected compensation expected to be paid to theCompany’s directors other than directors who are also NEOs during the year ended December 31, 2010.

NameFees

Earned

Share-basedawards

Option-basedawards

Non-equityincentive

plancompensation

Pensionvalue

All othercompensation Total

($) ($) (#) ($) ($) ($) ($)

William D. Armstrong . . . . . . . . . . . . . . . . . . . . — — 30,000 — — — —Robert W. Blakely . . . . . . . . . . . . . . . . . . . . . . . — — 30,000 — — — —Kevin J. Keenan . . . . . . . . . . . . . . . . . . . . . . . . . — — 30,000 — — — —Phillip A. Lamoreaux . . . . . . . . . . . . . . . . . . . . . — — 75,000 — — — —Clayton H. Riddell . . . . . . . . . . . . . . . . . . . . . . . — — 30,000 — — — —Robert N. Yurkovich . . . . . . . . . . . . . . . . . . . . . — — 30,000 — — — —

Note:(1) The market value of the Common Shares underlying these Options on both the date of grant and the date of this prospectus is not reasonably

ascertainable given that the Common Shares are not and have never been publicly listed or traded.

Long-Term Incentive Plans – Option Plan

Tourmaline has adopted the Option Plan for its Service Providers (as defined below).

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Purpose and Administration of the Option Plan

The purpose of the Option Plan is to develop the interest of existing or proposed officers, directors, employees andService Providers (as defined below) of the Company and its subsidiaries and other persons who provide or areproposed to provide ongoing management or consulting services to the Company or its subsidiaries in the growth anddevelopment of the Company by providing them with the opportunity through Options to acquire an increasedproprietary interest in the Company. For the purposes of the Option Plan, “Service Provider” means a person orcompany engaged, or proposed to be engaged, by the Company to provide services for an initial, renewable orextended period of 12 months or more.

The Option Plan is administered by the Board, or if appointed, by a committee of directors appointed from time totime by the Board pursuant to rules of procedure fixed by the Board. For the purposes of the following description ofthe Option Plan, references to the “Board” include any committee of directors appointed pursuant to the Option Plan.

Granting of Options

The Board has the authority to designate existing or proposed directors, officers, employees and Service Providersof the Company or its subsidiaries (collectively, the “Optionees”) to whom Options to purchase Common Shares maybe granted and the number of Common Shares to be optioned to each and may grant such Options, subject to theprovisions of the Option Plan and described below.

The Option Plan provides that:

(a) the number of Common Shares reserved for issuance on exercise of all Options outstanding under the OptionPlan at any time shall not exceed 10% of the Outstanding Common Shares (as defined in the Option Plan) atthe time in question (the “Common Share Maximum”) subject to adjustment as set forth in the Option Plan;

(b) the number of Common Shares reserved for issuance under the Option Plan to any one Optionee shall notexceed 5% of the Outstanding Common Shares;

(c) the number of Common Shares issuable to Insiders (as defined in the Option Plan), at any time, under allShare Compensation Arrangements (as defined in the Option Plan), shall not exceed 10% of the OutstandingCommon Shares; and

(d) the number of Common Shares issued to Insiders, within any one year period, under all Share CompensationArrangements, shall not exceed 10% of the Outstanding Common Shares,

provided that, for the purposes of paragraphs (c) and (d), an entitlement granted prior to the grantee becoming anInsider may be excluded in determining the number of Common Shares issued or issuable to Insiders.

Any increase in the Outstanding Common Shares (whether as a result of the exercise of Options or otherwise) willresult in an increase in the number of Common Shares that may be issued on exercise of Options outstanding at anytime and any decrease in the number of Options granted, due to the exercise of Options, will make new grants availableunder the Option Plan.

The Common Shares that are reserved for issuance on exercise of Options granted pursuant to the Option Plan thatare cancelled, terminated or expire prior to the exercise of all or a portion thereof are available for a subsequent grantof Options pursuant to the Option Plan to the extent of any Common Shares issuable thereunder that are not issuedunder such cancelled, terminated or expired Options.

Vesting

The Board may, in its sole discretion, determine the time during which Options will vest and the method ofvesting, or that no vesting restriction will exist. In the absence of any determination by the Board as to vesting, vestingwill be as to one third of the number of Options granted on the first anniversary of the date of grant and as to one thirdof the number of Options granted on the anniversary of the date of grant on each of the next two succeeding yearsthereafter. Notwithstanding the foregoing, vesting of Options will accelerate and Options will be exercisableimmediately prior to the time that a Change of Control (as defined in the Option Plan) takes place and as otherwiseprovided in the Option Plan. Further, the Board may, at its sole discretion at any time or in the option agreement inrespect of any Options granted, accelerate, or provide for the acceleration of, vesting of Options previously granted.

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Exercise Price

The exercise price (the “Exercise Price”) of any Option will be fixed by the Board when such Option is granted,provided that from and after the date that the Common Shares are listed on a stock exchange (the “Exchange”), suchprice shall not be less than the Current Market Price or such other minimum price permitted by such Exchange. For thispurpose, “Current Market Price” means the volume weighted average trading price of the Common Shares on theExchange (or if the Common Shares are listed on more than one stock exchange, on such stock exchange as may bedesignated by the Board for such purpose) for the five (5) trading days immediately preceding the date of grant ofOptions and, for this purpose, the weighted average trading price shall be calculated by dividing the total value by thetotal volume of Common Shares traded for such period; or, if the Common Shares are not listed on any Exchange, aprice determined by the Board.

Option Terms

The period during which an Option is exercisable is, subject to the provisions of the Option Plan requiringacceleration of rights of exercise, be such period as may be determined by the Board at the time of grant provided thatno Option may be exercised beyond five (5) years from the date of grant. Each Option will, among other things,contain provisions to the effect that the Option will be personal to the Optionee and will not be assignable. In addition,each Option will provide that:

(a) upon the death, permanent disability or normal retirement of the Optionee, the Option will terminate on thedate determined by the Board which will not be more than twelve (12) months from the date of death,permanent disability or normal retirement and, in the absence of any determination by the Board, will be thedate that is six (6) months following the date of death, permanent disability or normal retirement; and

(b) if the Optionee shall no longer be a director, officer, employee or Service Provider of the Company for anyreason other than as described above, the Option will terminate on the expiry of the period (the“Termination Date”) not in excess of thirty (30) days prescribed by the Board at the time of grant, followingthe date that the Optionee ceases to be a director, officer, employee or Service Provider of the Company or itssubsidiary, as the case may be,

provided that the number of Common Shares that the Optionee (or his heirs or successors) will be entitled to purchaseuntil the Termination Date: (i) will in the case of death of the Optionee, be all of the Common Shares that may beacquired on exercise of the Options held by such Optionee (or his or her heirs or successors) whether or not previouslyvested, and vesting of all such Options will be accelerated on the date of death for such purpose; and (ii) in any caseother than death or termination for cause, will be the number of Common Shares which the Optionee was entitled topurchase on the date the Optionee ceased to be an officer, director or employee of, or ceased providing ongoingmanagement or consulting services to, the Company, as the case may be.

For the purposes of the Option Plan and any Options granted pursuant to the Option Plan, the Optionee will bedeemed to have ceased to be an employee or Service Provider of the Company or any subsidiary of the Company, asapplicable, and the Optionee will be deemed to have terminated or resigned from employment or other servicearrangement with the Company for the purposes hereof or for the purposes of any Option issued pursuant to the termshereof on the first to occur of such termination or resignation or the date (as determined by the Board) that theOptionee ceases in the active performance of all of the regular duties of the Optionee’s job, which includes the carryingon of all of the usual and customary day-to-day duties of the job for the normal and scheduled number of hours in eachworking day, or the Optionee ceases to provide services pursuant to the services arrangement, as applicable; theforegoing to apply whether or not adequate or proper notice of termination shall have been provided by and to theCompany in respect of such termination of employment or other service arrangement.

Surrender Offer

An Optionee may make an offer (the “Surrender Offer”) to the Company, at any time, for the disposition andsurrender by the Optionee to the Company (and the termination thereof) of any of the Options granted pursuant to theOption Plan for an amount (not to exceed fair market value) specified therein by the Optionee and the Company may,but is not obligated to, accept the Surrender Offer, subject to any regulatory approval required. If the Surrender Offer,either as made or as renegotiated, is accepted, the Options in respect of which the Surrender Offer relates will besurrendered and deemed to be terminated and cancelled and will cease to grant the Optionee any further rightsthereunder upon payment of the amount of the agreed Surrender Offer by the Company to the Optionee.

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Mergers, Amalgamation and Sale

If the Company becomes merged (whether by plan of arrangement or otherwise) or amalgamated in or withanother company or entity or sells the whole or substantially the whole of its assets and undertakings for shares orsecurities of another company or other entity, the Company will, subject to the Option Plan, make provision that, uponexercise of an Option during its unexpired period after the effective date of such merger, amalgamation or sale, theOptionee will receive such number of shares of the continuing successor company or other entity in such merger oramalgamation or the securities or shares of the purchasing company or other entity as the Optionee would havereceived as a result of such merger, amalgamation or sale if the Optionee had purchased the shares of the Companyimmediately prior thereto for the same consideration paid on the exercise of the Option and had held such shares on theeffective date of such merger, amalgamation or sale and, upon such provision being made, the obligation of theCompany to the Optionee in respect of the Common Shares subject to the Option will terminate and be at an end andthe Optionee will cease to have any further rights in respect thereof. Alternatively, and in lieu of making suchprovision, in the event of such merger, amalgamation or sale, the Company may satisfy any obligations to an Optioneeby paying to the Optionee, in cash, the difference between the Exercise Price of all unexercised Options held by theOptionee and the fair market value of the securities to which the Optionee would be entitled upon exercise of allunexercised Options. Adjustments under the Option Plan or any determinations as to fair market value of any securitieswill be made by the Board, and any reasonable determination made by the Board will be binding and conclusive.

Acceleration of Vesting and Termination of Option in the Event of Take Over Bid

In the event of a Take-Over Bid (as defined in the Option Plan), Optionees have the right to exercise Optionsgranted pursuant to the Option Plan to purchase all of the Common Shares which have not been previously purchasedunder such Options, but any such Common Shares not otherwise vested and exercisable may only be purchased fortender pursuant to such Take-Over Bid. If for any reason such Common Shares are not so tendered or, if tendered, arenot for any reason taken up and paid for by the offeree pursuant to such Take-Over Bid, any such Common Shares sopurchased by an Optionee will be and be deemed to be cancelled and returned to treasury of the Company, will beadded back to the number of Common Shares, if any, remaining unexercised under the applicable Option and, uponpresentation to the Company of share certificates representing such shares properly endorsed for transfer back to theCompany, the Company will refund to the Optionee all consideration paid on the exercise thereof. In the event a Take-Over Bid is made and Common Shares are taken up and paid for pursuant to such Take-Over Bid, the Company willhave the right to satisfy any obligations to an Optionee in respect of any Options not exercised by paying to theOptionee, in cash, the difference between the Exercise Price of unexercised Options and the fair market value of thesecurities to which the Optionee would have been entitled upon exercise of the unexercised Options on such date,which determination of fair market value will be conclusively made by the Board. Upon payment as aforesaid, theOptions will terminate and be at an end and the Optionee will cease to have any further rights in respect thereof.

Alterations in Shares

In the event, at any time or from time to time, that the share capital of the Company shall be consolidated orsubdivided prior to the exercise by the Optionee, in full, of any Option in respect of all of the Common Shares grantedor the Company will pay a dividend (other than in the ordinary course) upon the Common Shares by way of issuance tothe holders thereof of additional Common Shares, securities or other assets, or other relevant changes in the sharecapital of the Company, Options with respect to any Common Shares which have not been purchased at the time of anysuch consolidation, subdivision, stock dividend or other change shall be proportionately adjusted (including as to thenumber of Common Shares subject to the Option and the exercise price thereof, as applicable) so that the Optionee willfrom time to time, upon the exercise of an Option, be entitled to receive the number of shares, securities or otherproperty of the Company he or she would have held following such consolidation, subdivision, stock dividend or otherchange if the Optionee had purchased the shares and had held such shares immediately prior to such consolidation,subdivision, stock dividend or other change. Upon any such adjustments being made, the Optionee will be bound bysuch adjustments and shall accept the terms of such Options in lieu of the Options previously outstanding.

For greater certainty, and anything above to the contrary notwithstanding, no adjustment will be made inaccordance with the Option Plan with respect to the issue of Common Shares being made pursuant to or in connectionwith:

(a) any stock option plan or stock purchase plan, including the Option Plan, in force from time to time forexisting or proposed officers, directors, employees or Service Providers of the Company; or

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(b) the issuance of additional Common Shares pursuant to a public offering or private placement by theCompany or a take-over bid made by the Company for the securities of another entity.

Option Agreements

A written agreement will be entered into between the Company and each Optionee to whom an Option is grantedpursuant to the Option Plan, which agreement will set out the number of Common Shares subject to Option, theExercise Price, provisions as to vesting and expiry and any other terms approved by the Board, all in accordance withthe provisions of the Option Plan. The agreement will be in such form as the Board may from time to time approve orauthorize the officers of the Company to enter into and may contain such terms as may be considered necessary inorder that the Option will comply with the Option Plan, any provisions respecting Options in the income tax or otherlaws in force in any country or jurisdiction of which the person to whom the Option is granted may from time to timebe a resident or citizen and the rules of any regulatory body having jurisdiction over the Company.

Regulatory Authorities Approvals

The Option Plan and the Company’s obligation to issue and deliver Common Shares under any Option is subjectto the approval, if required, of any Exchange on which the Common Shares are listed for trading. Any Options grantedprior to such approval, if required, is conditional upon such approval being given and no such Options may beexercised unless such approval, if required, is given.

Amendment or Discontinuance of the Option Plan

The Board may amend or discontinue the Option Plan and Options granted thereunder at any time withoutshareholder approval; provided any amendment to the Option Plan that requires approval of any stock exchange onwhich the Common Shares are listed for trading may not be made without approval of such stock exchange. Withoutthe prior approval of the shareholders, or such approval as may be required by the Exchange, the Board may not:

(a) make any amendment to the Option Plan to increase the Common Share Maximum;

(b) reduce the exercise price of any outstanding Options;

(c) extend the term of any outstanding Option beyond the original expiry date of such Option;

(d) make an amendment to increase the maximum limit on the number of securities that may be issued toinsiders;

(e) make any amendment to the Option Plan that would permit an Optionee to transfer or assign Options to anew beneficial Optionee other than in the case of death of the Optionee; or

(f) make an amendment to amend the amendment provisions of the Option Plan.

The Board may amend or terminate the Option Plan or any outstanding Option granted thereunder at any timewithout the approval of the Company, the shareholders of the Company or any Optionee whose Option is amended orterminated, in order to conform the Option Plan or such Option, as the case may be, to applicable law or regulation orthe requirements of any relevant stock exchange or regulatory authority, whether or not that amendment or terminationwould affect any accrued rights, subject to the approval of that stock exchange or regulatory authority.

In addition, no amendment to the Option Plan or Options granted pursuant to the Option Plan may be madewithout the consent of the Optionee, if it adversely alters or impairs any Option previously granted to such Optioneeunder the Option Plan.

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INDEBTEDNESS OF DIRECTORS AND OFFICERS

The Company is not aware of any individuals who are either current or former executive officers, directors oremployees of the Company or any of its subsidiaries and who have indebtedness outstanding as at the date hereof(whether entered into in connection with the purchase of securities of the Company or otherwise) that is owing to:(i) the Company or any of its subsidiaries; or (ii) another entity where such indebtedness is the subject of a guarantee,support agreement, letter of credit or other similar arrangement or understanding provided by the Company or any ofits subsidiaries.

Except for (i) indebtedness that has been entirely repaid on or before the date of this prospectus, and (ii) “routineindebtedness” (as defined in Form 51-102F5 of the Canadian Securities Administrators), the Company is not aware ofany individuals who are, or who at any time during 2009 were, a director or executive officer of the Company, aproposed nominee for election as a director or an associate of any of those directors, executive officers or proposednominees who are, or have been at any time since January 1, 2009, indebted to the Company or any of its subsidiaries,or whose indebtedness to another entity is, or at any time since January 1, 2009 has been, the subject of a guarantee,support agreement, letter of credit or other similar arrangement or understanding provided by the Company or any ofits subsidiaries.

AUDIT COMMITTEE AND CORPORATE GOVERNANCE

Audit Committee

The Audit Committee has been structured to comply with the requirements of NI 52-110. The Board hasdetermined that the Audit Committee members have the appropriate level of financial understanding and industry-specific knowledge to be able to perform their duties. A copy of the Audit Committee mandate and the additionaldisclosure required under NI 52-110 is attached to this prospectus as Appendix “B”.

Corporate Governance

The Company has adopted mandates, charters, position descriptions and corporate governance principles andpractices that are intended to respond to the independence and other governance standards and guidelines set out in NI52-109, NP 58-201 and NI 58-101. The corporate governance principles and practices address various matters,including:

Š responsibilities and duties of the Board;

Š composition of the Board, including criteria for remaining a director;

Š compensation of the Board;

Š composition and responsibilities of the Audit Committee and other Board committees;

Š relationship of the Board to management; and

Š director orientation and continuing education.

A copy of the Mandate of the Board of Directors and the additional disclosure required under NI 58-101 isattached to this prospectus as Appendix “A”.

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CERTAIN CANADIAN FEDERAL INCOME TAX CONSIDERATIONS

In the opinion of Burnet, Duckworth & Palmer LLP, counsel to the Company, and Blake, Cassels & GraydonLLP, counsel to the Underwriters, the following is a general summary, as of the date hereof, of the principal Canadianfederal income tax considerations under the Tax Act generally applicable to a holder who acquires such CommonShares pursuant to the Offering and who, for the purposes of the Tax Act and at all relevant times, beneficially ownsCommon Shares as capital property, and deals at arm’s length with, and is not affiliated with, the Company (a“Holder”). The Common Shares will generally be considered to be capital property for this purpose unless either theHolder holds (or will hold) such Common Shares in the course of carrying on a business, or the Holder has acquired (orwill acquire) such Common Shares in a transaction or transactions considered to be an adventure or concern in thenature of trade.

This summary is not applicable to: (a) a Holder that is a “financial institution”, as defined in the Tax Act forpurposes of the mark-to-market rules; (b) a Holder, an interest in which would be a “tax shelter investment” as definedin the Tax Act; (c) a Holder that is a “specified financial institution” as defined in the Tax Act; (d) a Holder that is apartnership or a trust; or (e) a Holder that is a corporation that has elected in the prescribed form and manner and hasotherwise met the requirements to use functional currency tax reporting as set out in the Tax Act. Any such Holder towhich this summary does not apply should consult its own tax advisor.

This summary is based upon the current provisions of the Tax Act and counsel’s understanding of the currentpublished administrative and assessing policies and practices of the Canada Revenue Agency. The summary also takesinto account all specific proposals to amend the Tax Act that have been publicly announced by or on behalf of theMinister of Finance (Canada) prior to the date hereof (the “Tax Proposals”), and assumes that all such Tax Proposalswill be enacted in the form proposed. No assurance can be given that the Tax Proposals will be enacted in the formproposed or at all. This summary does not otherwise take into account or anticipate any changes in law, whether byway of legislative, judicial or administrative action or interpretation, nor does it address any provincial, territorial orforeign tax considerations.

This summary is of a general nature only and is not intended to be, nor should it be construed to be, legal ortax advice to any particular Holder. Accordingly, Holders are urged to consult their own tax advisors about thespecific tax consequences to them of acquiring, holding and disposing of Common Shares.

Residents of Canada

The following discussion applies to Holders who, for the purposes of the Tax Act and any applicable income taxtreaty or convention, and at all relevant times, are resident in Canada (“Resident Holders”). Certain Resident Holderswhose Common Shares might not otherwise qualify as capital property may, in certain circumstances, make anirrevocable election pursuant to subsection 39(4) of the Tax Act such that the Common Shares and every “Canadiansecurity” (as defined in the Tax Act) owned by the Resident Holder in the taxation year of the election and in allsubsequent taxation years are deemed to be capital property.

Dividends on Common Shares

Dividends received or deemed to be received on the Common Shares by a Resident Holder who is an individual(other than certain trusts) will be included in income and will be subject to the gross-up and dividend tax credit rulesnormally applicable under the Tax Act to taxable dividends received from taxable Canadian corporations. TheCompany may, upon notice to its shareholders, designate all or a portion of such dividends as “eligible dividends” thatare entitled to the enhanced dividend tax credit. The amount of the dividend received by an individual but not theamount of the gross-up, may be subject to alternative minimum tax.

Dividends received or deemed to be received on Common Shares by a Resident Holder that is a corporation willbe included in its income and will generally also be deductible in computing its taxable income. A Resident Holder thatis a “private corporation” or a “subject corporation”, each as defined in the Tax Act, may be liable under Part IV of theTax Act to pay a refundable tax at a rate of 331⁄3% on dividends received or deemed to be received on Common Sharesto the extent such dividends are deductible in computing the Resident Holder’s taxable income.

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Dispositions of Common Shares

A disposition, or a deemed disposition, of a Common Share (other than to the Company unless purchased by theCompany in the open market in the manner in which shares are normally purchased by any member of the public in theopen market) by a Resident Holder will generally give rise to a capital gain (or a capital loss) equal to the amount bywhich the proceeds of disposition of the Common Share, net of any reasonable costs of disposition, exceed (or are lessthan) the adjusted cost base of the Common Share to the Holder. For this purpose, the adjusted cost base to a ResidentHolder of a Common Share will be determined at any time by averaging the cost of such Common Share with theadjusted cost base of any other Common Shares owned by the holder as capital property at that time. The taxation ofcapital gains and losses is described below under “Taxation of Capital Gains and Capital Losses”.

Refundable Tax

A Resident Holder that is throughout the year a “Canadian-controlled private corporation” (as defined in the TaxAct) may be liable to pay a refundable tax at a rate of 62⁄3% on certain investment income, including taxable capitalgains (as defined below), but excluding dividends or deemed dividends deductible in computing taxable income.

Taxation of Capital Gains and Capital Losses

Generally, one-half of any capital gain (a taxable capital gain) realized by a Resident Holder for a taxation yearmust be included in the Resident Holder’s income in the year. A Resident Holder is required to deduct one-half of anycapital loss (an allowable capital loss) realized in the year from taxable capital gains realized in that year, andallowable capital losses in excess of taxable capital gains may be carried back and deducted in any of the threepreceding taxation years, or in any subsequent year, from net taxable capital gains realized in such years (but notagainst other income) to the extent and under the circumstances described in the Tax Act. If the Resident Holder is acorporation, any such capital loss realized on the sale of a Common Share may in certain circumstances be reduced bythe amount of any dividends which have been received or which are deemed to have been received on the CommonShare. Similar rules may apply where a corporation is a member of a partnership or a beneficiary of a trust that ownsshares, directly or indirectly, through a partnership or a trust. Taxable capital gains realized by a Resident Holder whois an individual may give rise to alternative minimum tax depending on the Resident Holder’s circumstances.

Non-Resident Holders

The following discussion applies to a Holder who, for the purposes of the Tax Act and any applicable income taxtreaty or convention, and at all relevant times, is not (and is not deemed to be) resident in Canada and will not use orhold (and will not be deemed to use or hold) the Common Shares in, or in the course of, carrying on a business or partof a business in Canada (a “Non-Resident Holder”). In addition, this discussion does not apply to a “registerednon-resident insurer” or an “authorized foreign bank”, both within the meaning of the Tax Act.

Dividends on Common Shares

Canadian withholding tax at a rate of 25% (subject to reduction under the provisions of any applicable income taxtreaty or convention) will be payable on dividends paid or credited, or deemed to be paid or credited on the CommonShares, to a Non-Resident Holder. The rate of withholding tax applicable to a dividend paid on the Common Shares toa Non-Resident Holder who is a resident of the U.S. for purposes of the Canada-U.S. Income Tax Convention (the“Convention”), beneficially owns the dividend and qualifies for the benefits of the Convention will generally bereduced to 15% or, if the Non-Resident Holder is a corporation that owns at least 10% of the voting stock of theCompany, to 5%. Not all persons who are residents of the U.S. for purposes of the Convention will qualify for thebenefits of the Convention. A Non-Resident Holder who is a resident of the U.S. is advised to consult its tax advisor inthis regard. The rate of withholding tax on dividends is also reduced under certain other bilateral income tax treaties orconventions to which Canada is a signatory.

Dispositions of Common Shares

A Non-Resident Holder will not be subject to tax under the Tax Act in respect of any capital gain realized by suchNon-Resident Holder on a disposition of Common Shares unless the Common Shares constitute “taxable Canadian

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property” (as defined in the Tax Act) of the Non-Resident Holder at the time of disposition and the holder is notentitled to relief under an income tax treaty or convention. As long as the Common Shares are listed on a “designatedstock exchange”, which currently includes the TSX, the Common Shares generally will not constitute taxable Canadianproperty of a Non-Resident Holder. The Common Shares may constitute taxable Canadian property to a Non-ResidentHolder even if the Common Shares are listed on the TSX (or another designated stock exchange) if at any time duringthe 60-month period immediately preceding the disposition the Non-Resident Holder, persons with whom theNon-Resident Holder did not deal at arm’s length, or the Non-Resident Holder together with all such persons, owned25% or more of the issued shares of any class or series of shares of the capital stock of the Company.

If the Common Shares are considered taxable Canadian property to a Non-Resident Holder, an applicable incometax treaty or convention may exempt that Non-Resident Holder from tax under the Tax Act in respect of theirdisposition.

As long as the Common Shares are listed at the time of their disposition on the TSX or another “recognized stockexchange”, as defined in the Tax Act, a Non-Resident Holder who disposes of Common Shares that are taxableCanadian property will not be required to satisfy the obligations imposed under section 116 of the Tax Act.

ELIGIBILITY FOR INVESTMENT

In the opinion of Burnet, Duckworth & Palmer LLP, counsel to the Company, and Blake, Cassels & GraydonLLP, counsel to the Underwriters, on the date of the Offering, provided that the Common Shares are listed on adesignated stock exchange (which includes the TSX), the Common Shares will on that date be a qualified investmentunder the Tax Act for trusts governed by registered retirement savings plans, registered retirement income funds,registered disability savings plans, deferred profit sharing plans, registered education savings plans and tax-free savingsaccounts as defined in the Tax Act.

Notwithstanding the foregoing, if the Common Shares are “prohibited investments” for purposes of the Tax Act, aholder will be subject to a penalty tax on Common Shares held in a tax-free savings account as set out in the Tax Act.A Common Share will not be a prohibited investment for a trust governed by a tax-free savings account held by aparticular holder provided that the holder deals at arm’s length with the Company for purposes of the Tax Act, anddoes not have a “significant interest” (as defined in the Tax Act) in either the Company or a person or partnership thatdoes not deal at arm’s length with the Company for the purposes of the Tax Act. Generally, a holder will not beconsidered to have a significant investment in the Company or any other corporation unless the holder is a “specifiedshareholder” (for purposes of the Tax Act) of the Company or such other corporation, as the case may be.

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PLAN OF DISTRIBUTION

General

The Company is offering the Common Shares described in this prospectus through the Underwriters. TheCompany has entered into the Underwriting Agreement dated November 15, 2010 with the Underwriters. Subject to theterms and conditions of the Underwriting Agreement, each of the Underwriters has severally agreed to purchase theCommon Shares offered hereby.

Closing of the Offering is expected to occur on or about November 23, 2010 or such later date as the Companyand the Underwriters may agree, but in any event not later than December 15, 2010, at a price of $21.00 per CommonShare payable in cash to the Company against delivery of certificates representing the Common Shares.

The obligations of the Underwriters are several and neither joint, nor joint and several, and may be terminated attheir discretion on the basis of their assessment of the state of the financial markets and may also be terminated uponthe occurrence of certain stated events. The Underwriting Agreement provides that the Underwriters must take up andpay for all of the Common Shares by December 15, 2010 if any of the Common Shares are purchased under theUnderwriting Agreement. However, the Underwriters are not required to take up or pay for the Common Sharescovered by the Underwriters’ Over-Allotment Option described below. The Common Shares are offered subject to anumber of conditions, including, receipt and acceptance of the Common Shares by the Underwriters and theUnderwriters’ right to reject orders in whole or in part compliance by the Company with industry standard closingconditions and the compliance with all applicable legal requirements. In connection with the Offering, certain of theUnderwriters or securities dealers may distribute prospectuses electronically.

The Offering is being made in each of the provinces of Canada. The Common Shares will be offered in each of theprovinces of Canada through those Underwriters or their affiliates who are registered to offer the Common Shares forsale in such provinces and such other registered dealers as may be designated by the Underwriters. Subject toapplicable law, the Underwriters may offer the Common Shares outside of Canada.

The Toronto Stock Exchange (the “TSX”) has conditionally approved the listing of the Common Shares under thesymbol “TOU”, subject to the Company fulfilling all the listing requirements of the TSX on or before February 8,2011.

The Common Shares have not been and will not be registered under the U.S. Securities Act or any state securitieslaws, and, subject to certain exceptions, may not be offered or sold in the United States, except in transactions exemptfrom registration under the U.S. Securities Act and under the securities laws of any applicable state. The Underwritershave agreed that they will not offer or sell the Common Shares within the United States except in accordance with Rule144A under the U.S. Securities Act and in compliance with applicable state securities laws, except that the CommonShares comprising the Offering may also be offered within the United States by the Underwriters through their U.S.registered broker-dealer affiliates, for sale directly by the Company, to institutional “accredited investors” (within themeaning of Rule 501(a)(1), (2), (3) or (7) of Regulation D under the U.S. Securities Act) in transactions in accordancewith Rule 506 of Regulation D under the U.S. Securities Act and in compliance with applicable state securities laws.This prospectus does not constitute an offer to sell or a solicitation of an offer to buy any of the Common Shares in theUnited States. In addition, until 40 days after the commencement of the Offering, an offer or sale of Common Shareswithin the United States by any dealer (whether or not participating in the Offering) may violate the registrationrequirements of the U.S. Securities Act if such offer or sale is made otherwise than in accordance with an exemptionfrom the registration requirements of the U.S. Securities Act.

Prior to the Offering, there has been no public market for the Common Shares. The sale of a substantial number ofthe Common Shares in the public market after the Offering, or the perception that such sales may occur, couldadversely affect the prevailing market price of the Common Shares. See “Risk Factors – Risks Related to the Offering– Absence of a Liquid, Public Market.”

Upon the completion of the Offering and the Concurrent Private Placement, the Company expects to have a totalof 134,691,060 outstanding Common Shares (136,191,060 if the Over-Allotment Option is exercised in full). All of theCommon Shares sold in the Offering will be freely tradable in Canada without restriction or further registration underapplicable Canadian securities laws.

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Subscriptions will be received subject to rejection or allotment in whole or in part and the Underwriters reservethe right to close the subscription books at any time without notice. It is expected that certificates representing theCommon Shares to be issued and sold in the Offering will be available for delivery on the date of Closing. TheCommon Shares offered under this prospectus (other than any Common Shares issuable on exercise of the Over-Allotment Option) are to be taken up by the Underwriters, if at all, on or before a date not later than 42 days after thedate of the receipt for the final prospectus.

Over-Allotment Option

The Company has granted to the Underwriters the Over-Allotment Option, exercisable at the Underwriters’ solediscretion at any time, in whole or in part, at any time on or before the date that is 30 days following the Closing Date,to purchase up to an additional 1,500,000 Common Shares (representing 15% of the Common Shares offeredhereunder) from the Company on the same terms as set forth above, for the purpose of covering over-allocations, ifany. This prospectus also qualifies the grant of the Over-Allotment Option and the distribution of the Common Sharesto be delivered upon the exercise of the Over-Allotment Option.

A purchaser who acquires Common Shares forming part of the Underwriters’ over-allocation position acquiressuch Common Shares under this prospectus, regardless of whether the over-allocation position is ultimately filledthrough the exercise of the Over-Allotment Option or secondary market purchases.

Price Stabilization, Short Positions and Passive Market Making

In connection with the Offering, the Underwriters may over–allocate or effect transactions which stabilize ormaintain the market price of the Common Shares at levels other than those which otherwise might prevail on the openmarket, including: stabilizing transactions; short sales; purchases to cover positions created by short sales; impositionof penalty bids; and syndicate covering transactions.

Stabilizing transactions consist of bids or purchases made for the purpose of preventing a decline in the market priceof the Common Shares while the Offering is in progress. These transactions may also include making short sales of theCommon Shares, which involve the sale by the Underwriters of a greater number of Common Shares than they arerequired to purchase in the Offering. Short sales may be “covered short sales”, which are short positions in an amount notgreater than the Over-Allotment Option, or may be “naked short sales”, which are short positions in excess of that amount.The Underwriters may close out any covered short position either by exercising the Over-Allotment Option, in whole or inpart, or by purchasing Common Shares in the open market. In making this determination, the Underwriters will consider,among other things, the price of Common Shares available for purchase in the open market compared with the price atwhich they may purchase Common Shares through the Over-Allotment Option. The Underwriters must close out anynaked short position by purchasing Common Shares in the open market. A naked short position is more likely to becreated if the Underwriters are concerned that there may be downward pressure on the price of the Common Shares in theopen market that could adversely affect purchasers who purchase in the Offering.

In addition, in accordance with rules and policy statements of certain Canadian securities regulators, theUnderwriters may not, at any time during the period of distribution, bid for or purchase Common Shares. Theforegoing restriction is, however, subject to exceptions where the bid or purchase is not made for the purpose ofcreating actual or apparent active trading in, or raising the price of, the Common Shares. These exceptions include abid or purchase permitted under the by-laws and rules of applicable regulatory authorities and the applicable stockexchange, including the Universal Market Integrity Rules for Canadian Marketplaces, relating to market stabilizationand passive market making activities and a bid or purchase made for and on behalf of a customer where the order wasnot solicited during the period of distribution.

As a result of these activities, the price of the Common Shares may be higher than the price that otherwise mightexist in the open market. If these activities are commenced, they may be discontinued by the Underwriters at any time.The Underwriters may carry out these transactions on any stock exchange on which the Common Shares are listed, inthe over-the-counter market or otherwise.

Pricing of the Offering

Prior to the Offering, there was no public market for the Common Shares. The Offering Price was determined bynegotiation between the Company and the Underwriters. Among the factors considered in determining the Offering

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Price will be the experience and track record of the Company’s management, the Company’s future prospects anddrilling inventory and future prospects of the oil and gas industry in general, the Company’s revenue, earnings andother financial and operating information in recent periods, and the debt adjusted cash flow multiples, netbacks,prospect drilling inventory, per flowing Boe metrics and market prices of securities and financial and operatinginformation of companies engaged in activities similar to the Company’s.

The Underwriters propose to offer the Common Shares initially at the Offering Price. After the Underwriters havemade a reasonable effort to sell all of the Common Shares at the Offering Price, the Offering Price may be decreased andmay be further changed from time to time to an amount not greater than the Offering Price, provided the compensationrealized by the Underwriters will be decreased by the amount that the aggregate price paid by purchasers for the CommonShares is less than the gross purchase price paid by the Underwriters to the Company for the Common Shares. For greatercertainty, in the event the Offering Price is decreased the proceeds to be received by the Company will remain unchanged.

Commission

The Company will pay the Underwriters $1.155 per Common Share for each share sold by it at the Offering Price,for a total of $11,550,000 ($13,282,500 if the Over-Allotment is exercised in full).

Expenses Related to the Offering

It is estimated that the total expenses of the Offering, not including the Underwriters’ Commission, will beapproximately $3,750,000.

Restrictions on Further Sales of Common Shares by the Company

Pursuant to the Underwriting Agreement, the Company has agreed that, during the period beginning on the ClosingDate and ending on the date that is 180 days after the Closing Date, the Company shall not, directly or indirectly,without the prior written consent of the Lead Underwriter (such consent not to be unreasonably withheld or delayed)issue, offer or grant any option, warrant or other right to purchase or agree to issue or sell, or otherwise lend, transfer,assign, pledge or dispose of (including without limitation by making any short sale, engaging in any hedging,monetization or derivative transaction or entering into any swap or other arrangement that transfers to another, in wholeor in part, any of the economic consequences of ownership of Common Shares or other equity securities of the Companyor securities convertible into, exchangeable for, or otherwise exercisable into Common Shares or other equity securitiesof the Company, whether or not cash settled), in a public offering or by way of private placement or otherwise, anyequity securities of the Company or other securities convertible into, exchangeable for, or otherwise exercisable intoCommon Shares or other equity securities of the Company, or agree to do any of the foregoing or publicly announce anyintention to do any of the foregoing, other than: (a) the Common Shares issued under this prospectus, the ConcurrentPrivate Placement and the Common Shares issued pursuant to the Over-Allotment Option, if any; and (b) Optionsgranted under the Option Plan and Common Shares issued upon the exercise of such Options.

CONCURRENT PRIVATE PLACEMENT

In addition to, and apart from, the Offering, the Private Placees have each entered into a subscription agreementwith the Company pursuant to which the Private Placees will purchase, pursuant to the Concurrent Private Placement,an aggregate of 850,000 Private Placement Shares at the Offering Price for gross proceeds to the Company of$17,850,000. No commission is payable to the Underwriters in connection with the Concurrent Private Placement.

The Board of Directors approved the Concurrent Private Placement at the same time as it approved the Offering,on the basis that the Concurrent Private Placement will be effected at the same issue price as the Offering. Messrs.Rose and Yurkovich abstained from voting with respect to the Concurrent Private Placement.

The Private Placement Shares issued pursuant to the Concurrent Private Placement will be subject to restrictionson resale for a period of four months under applicable securities legislation. The Concurrent Private Placement hasbeen conditionally approved by the TSX. This prospectus does not qualify the distribution of the Private PlacementShares issuable by the Company to the Private Placees pursuant to the Concurrent Private Placement.

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RELATIONSHIP BETWEEN THE COMPANY AND CERTAIN OF THE UNDERWRITERS

Scotia Capital Inc. and TD Securities Inc. are subsidiaries of Canadian chartered banks (collectively, the “Banks”)that are lenders to the Company. Consequently, the Company may be considered to be a “connected issuer” of suchunderwriters under applicable Canadian securities laws.

As of November 15, 2010, the Company was indebted to the Banks under the Credit Facilities for approximately$113.7 million. The Credit Facilities are secured by general security agreements and demand loan debentures securedby first floating charges over all of the Company’s consolidated assets. As of the date of this prospectus, the Companyand Exshaw are in compliance in all material respects with the terms of their respective indebtedness to the Banksunder the Credit Facilities. None of the Banks have waived any breach of the Credit Facilities since their execution.Neither the Company’s financial position nor the value of the security under the Credit Facilities has changed adverselysince the indebtedness under the Credit Facilities was incurred. For a description of the material terms of the CreditFacilities see Note 1 to the table under the heading “Consolidated Capitalization”.

None of the Banks were involved in the decision to undertake the Offering or were involved in the determinationof the terms of the Offering, including structure and pricing. As a consequence of the Offering, the above Underwriterswill receive a commission in respect of the Common Shares sold through the Underwriters. See “Use of Proceeds”.

Certain of the Underwriters and their respective affiliates have, from time to time, performed, and may in thefuture perform, various financial advisory and investment banking services for the Company, for which they receivedor will receive customary fees.

MARKET FOR SECURITIES

There is no market through which the Common Shares may be sold and purchasers may not be able to resell theCommon Shares purchased under this prospectus. See “Risk Factors – Risks Related to the Offering – Absence of aLiquid, Public Market.”

INDUSTRY CONDITIONS

Companies operating in the oil and natural gas industry are subject to extensive regulation and control ofoperations (including land tenure, exploration, development, production, refining, transportation, and marketing) as aresult of legislation enacted by various levels of government and with respect to the pricing and taxation of oil andnatural gas through agreements among the governments of Canada, Alberta and British Columbia, all of which shouldbe carefully considered by investors in the oil and natural gas industry. It is not expected that any of these regulationsor controls will affect the Company’s operations in a manner materially different than they will affect other oil andnatural gas companies of similar size. All current legislation is a matter of public record and the Company is unable topredict what additional legislation or amendments may be enacted. Outlined below are some of the principal aspects oflegislation, regulations and agreements governing the oil and natural gas industry.

Pricing and Marketing

Crude Oil

The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that themarket determines the price of oil. Oil prices are primarily based on worldwide supply and demand. The specific pricedepends in part on oil quality, prices of competing fuels, distance to market, the value of refined products, the supply/demand balance and contractual terms of sale. Oil exporters are also entitled to enter into export contracts with termsnot exceeding one year in the case of oil, other than heavy oil, and two years in the case of heavy crude oil, providedthat an order approving such export has been obtained from the National Energy Board of Canada (the “NEB”). Anyoil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter toobtain an export licence from the NEB and the issuance of such a licence requires a public hearing and the approval ofthe Governor in Council.

Natural Gas

The price of the vast majority of natural gas produced in western Canada is now determined through the liquidmarket established at the Alberta “NIT” hub rather than through direct negotiation between buyers and sellers. Natural

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gas exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free tonegotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain othercriteria prescribed by the NEB and the Government of Canada. Natural gas (other than propane, butane and ethane)exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 m3/day)must be made pursuant to an NEB order. Any natural gas export to be made pursuant to a contract of longer duration(to a maximum of 25 years) or for a larger quantity requires an exporter to obtain an export licence from the NEB andthe issuance of such a licence requires a public hearing and the approval of the Governor in Council.

The governments of Alberta and British Columbia also regulate the volume of natural gas that may be removedfrom those provinces for consumption elsewhere based on such factors as reserve availability, transportationarrangements, and market considerations.

Pipeline Capacity

As a result of pipeline expansions over the past several years, there is ample pipeline capacity to accommodatecurrent production levels of oil and natural gas in western Canada and pipeline capacity does not generally limit theability to produce and market such production.

The North American Free Trade Agreement

The North American Free Trade Agreement (“NAFTA”) among the governments of Canada, the United States andMexico became effective on January 1, 1994. NAFTA carries forward most of the material energy terms that are contained inthe Canada United States Free Trade Agreement. In the context of energy resources, Canada continues to remain free todetermine whether exports of energy resources to the United States or Mexico will be allowed, provided that any exportrestrictions do not: (i) reduce the proportion of energy resources exported relative to domestic use (based upon the proportionprevailing in the most recent 36 month period); (ii) impose an export price higher than the domestic price (subject to anexception with respect to certain voluntary measures which only restrict the volume of exports); and (iii) disrupt normalchannels of supply. All three signatory countries are prohibited from imposing minimum or maximum export or import pricerequirements, provided, in the case of export price requirements, that any prohibition in any circumstances in which any otherform of quantitative restriction is applied is prohibited, and in the case of import-price requirements, that such requirementsdo not apply with respect to enforcement of countervailing and anti-dumping orders and undertakings.

NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector by 2010 andprohibits discriminatory border restrictions and export taxes. NAFTA also contemplates clearer disciplines onregulators to ensure fair implementation of any regulatory changes, minimize disruption of contractual arrangementsand avoid undue interference with pricing, marketing and distribution arrangements, all of which are important forCanadian oil and natural gas exports.

Royalties and Incentives

General

In addition to federal regulation, each province has legislation and regulations which govern royalties, productionrates and other matters. The royalty regime in a given province is a significant factor in the profitability of crude oil,NGL, sulphur and natural gas production. Royalties payable on production from lands other than Crown lands aredetermined by negotiation between the mineral freehold owner and the lessee, although production from such lands issubject to certain provincial taxes and royalties. Royalties from production on Crown lands are determined bygovernmental regulation and are generally calculated as a percentage of the value of gross production. The rate ofroyalties payable generally depends in part on prescribed reference prices, well productivity, geographical location,field discovery date, method of recovery and the type or quality of the petroleum product produced. Other royalties androyalty-like interests are, from time to time, carved out of the working interest owner’s interest through non-publictransactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests or netcarried interests.

Occasionally the governments of the western Canadian provinces create incentive programs for exploration anddevelopment. Such programs often provide for royalty rate reductions, royalty holidays or royalty tax credits and aregenerally introduced when commodity prices are low to encourage exploration and development activity by improvingearnings and cash flow within the industry.

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Alberta

Producers of oil and natural gas from Crown lands in Alberta are required to pay annual rental payments, currentlyat a rate of $3.50 per hectare, and make monthly royalty payments in respect of oil and natural gas produced.

On October 25, 2007, the Government of Alberta released a report entitled “The New Royalty Framework”(“NRF”) containing the Government’s proposals for Alberta’s new royalty regime which were subsequentlyimplemented by the Mines and Minerals (New Royalty Framework) Amendment Act, 2008. The NRF took effect onJanuary 1, 2009. On March 11, 2010, the Government of Alberta announced changes to Alberta’s royalty systemintended to increase Alberta’s competitiveness in the upstream oil and natural gas sectors; specifically, the maximumroyalty rates for conventional oil and natural gas production will be decreased effective for the January 2011production month and certain temporary incentive programs currently in place will be made permanent. Further detailswith respect to the changes to Alberta’s royalty system are expected to be provided in the coming months.

With respect to conventional oil, the NRF eliminated the classification system used by the previous royaltystructure which classified oil based on the date of discovery of the pool. Under the NRF, royalty rates for conventionaloil are set by a single sliding rate formula which is applied monthly and incorporates separate variables to account forproduction rates and market prices. Royalty rates for conventional oil under the NRF range from 0-50%, an increasefrom the previous maximum rates of 30-35% depending on the vintage of the oil, and rate caps are set at $120 perbarrel. Effective January 1, 2011, the maximum royalty payable under the NRF will be reduced to 40%.

Royalty rates for natural gas under the NRF are similarly determined using a single sliding rate formulaincorporating separate variables to account for production rates and market prices. Royalty rates for natural gas underthe NRF range from 5-50%, an increase from the previous maximum rates of 5-35%, and rate caps are set at$17.75/GJ. Effective January 1, 2011, the maximum royalty payable under the NRF will be reduced to 36%.

Oil sands projects are also subject to the NRF. Prior to payout, the royalty is payable on gross revenues of an oilsands project. Gross revenue royalty rates range between 1-9% depending on the market price of oil: rates are 1% whenthe market price of oil is less than or equal to $55 per barrel and increase for every dollar of market price of oil increaseto a maximum of 9% when oil is priced at $120 or higher. After payout, the royalty payable is the greater of the grossrevenue royalty based on the gross revenue royalty rate of 1-9% and the net revenue royalty based on the net revenueroyalty rate. Net revenue royalty rates start at 25% and increase for every dollar of market price of oil increase above$55 up to 40% when oil is priced at $120 or higher. An oil sands project reaches payout when its cumulative revenueexceeds its cumulative costs. Costs include specified allowed capital and operating costs related to the project plus aspecified return allowance. As part of the implementation of the NRF, the Government of Alberta renegotiated existingcontracts with certain oil sands producers that were not compatible with the NRF.

In April 2005, the Government of Alberta introduced the Innovative Energy Technologies Program (the “IETP”),which has a stated objective of promoting producers’ investment in research, technology and innovation for the purposesof improving environmental performance while creating commercial value. The IETP is backed by a $200 million fundingcommitment over a five-year period beginning April 1, 2005 and provides royalty adjustments to specific pilot anddemonstration projects that utilize innovative technologies to increase recovery from existing reserves.

On April 10, 2008, the Government of Alberta introduced two new royalty programs to be implemented alongwith the NRF and intended to encourage the development of deeper, higher cost oil and gas reserves. A five-yearprogram for conventional oil exploration wells over 2,000 metres provides qualifying wells with up to a $1 million or12 months of royalty relief, whichever comes first, and a five-year program for natural gas wells deeper than 2,500metres provides a sliding scale royalty credit based on depth of up to $3,750 per metre.

On November 19, 2008, in response to the drop in commodity prices experienced during the second half of 2008,the Government of Alberta announced the introduction of a five-year program of transitional royalty rates with theintent of promoting new drilling. The 5-year transition option is designed to provide lower royalties at certain pricelevels in the initial years of a well’s life when production rates are expected to be the highest. Under this new programcompanies drilling new natural gas or conventional oil deep wells (between 1,000 and 3,500 m) are given a one-timeoption, on a well-by-well basis, to adopt either the new transitional royalty rates or those outlined in the NRF. Pursuantto the changes made to Alberta’s royalty structure announced on March 11, 2010, producers will only be able to electto adopt the transitional royalty rates prior to January 1, 2011 and producers that have already elected to adopt the

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transitional royalty rates as of that date will be permitted to switch to Alberta’s conventional royalty structure. OnDecember 31, 2013, all producers operating under the transitional royalty rates will automatically become subject toAlberta’s conventional royalty structure.

On March 3, 2009, the Government of Alberta announced a three-point incentive program in order to stimulatenew and continued economic activity in Alberta. The program introduced a drilling royalty credit for new conventionaloil and natural gas wells and a new well royalty incentive program, both applying to conventional oil or natural gaswells drilled between April 1, 2009 and March 31, 2010. The drilling royalty credit provides up to a $200 per metreroyalty credit for new wells and is primarily expected to benefit smaller producers since the maximum credit availablewill be determined using the company’s production level in 2008 and its drilling activity between April 1, 2009 andMarch 31, 2010, favouring smaller producers with lower activity levels. The new well incentive program initiallyapplied to wells that began producing conventional oil or natural gas between April 1, 2009 and March 31, 2010 andprovided for a maximum 5% royalty rate for the first 12 months of production on a maximum of 50,000 barrels of oilor 500 MMcf of natural gas. In June 2009, the Government of Alberta announced the extension of these two incentiveprograms for one year to March 31, 2011. On March 11, 2010, the Government of Alberta announced that the incentiveprogram rate of 5% for the first 12 months of production would be made permanent, with the same volume limitations.

In addition to the foregoing, Alberta currently maintains a royalty reduction program for low productivity oil andoil sands wells, a royalty adjustment program for deep marginal natural gas wells and a royalty exemption for re-entrywells, among others.

British Columbia

Producers of oil and natural gas from Crown lands in British Columbia are required to pay annual rentalpayments, currently at a rate of $3.50 per hectare, and make monthly royalty payments in respect of oil and natural gasproduced. The amount payable as a royalty in respect of oil depends on the type and vintage of the oil, the quantity ofoil produced in a month and the value of that oil. Generally, oil is classified as either light or heavy and the vintage ofoil is based on the determination of whether the oil is produced from a pool discovered before October 31, 1975 (“oldoil”), between October 31, 1975 and June 1, 1998 (“new oil”), or after June 1, 1998 (“third-tier oil”). The royaltycalculation takes into account the production of oil on a well-by-well basis, the specified royalty rate for a givenvintage of oil, the average unit selling price of the oil and any applicable royalty exemptions. Royalty rates are reducedon low productivity wells, reflecting the higher unit costs of extraction, and are the lowest for third-tier oil, reflectingthe higher unit costs of both exploration and extraction.

The royalty payable in respect of natural gas produced on Crown lands is determined by a sliding scale formulabased on a reference price, which is the greater of the average net price obtained by the producer and a prescribedminimum price. For non-conservation gas (not produced in association with oil), the royalty rate depends on the date ofacquisition of the oil and natural gas tenure rights and the spud date of the well and may also be impacted by the selectprice, a parameter used in the royalty rate formula to account for inflation. Royalty rates are fixed for certain classes ofnon-conservation gas when the reference price is below the select price. Conservation gas is subject to a lower royaltyrate than non-conservation gas as an incentive for the production and marketing of natural gas which might otherwisehave been flared.

Producers of oil and natural gas from freehold lands in British Columbia are required to pay monthly freeholdproduction taxes. For oil, the level of the freehold production tax is based on the volume of monthly production. Fornatural gas, the freehold production tax is determined using a sliding scale formula based on the reference price similarto that applied to natural gas production on Crown land, and depends on whether the natural gas is conservation gas ornon-conservation gas.

As at the beginning of 2009, British Columbia maintained a number of targeted royalty programs for key resourceareas intended to increase the competitiveness of British Columbia’s low productivity wells. These include both royaltycredit and royalty reduction programs, including the following:

Š Summer Royalty Credit Program providing a royalty credit of 10% of drilling and completion costs up to$100,000 for wells drilled between April 1 and November 30 of each year, intended to increase summerdrilling activity, employment and business opportunities in north eastern British Columbia;

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Š Deep Royalty Credit Program providing a royalty credit equal to approximately 23% of drilling andcompletion costs for vertical wells with a true vertical depth greater than 2,500 metres and horizontal wellswith a true vertical depth greater than 2,300 metres spud between December 1, 2003 and September 1, 2009;

Š Deep Re-Entry Royalty Credit Program providing royalty credits for deep re-entry wells with a true verticaldepth greater than 2,300 metres and a re-entry date subsequent to December 1, 2003;

Š Deep Discovery Royalty Credit Program providing the lesser of a 3-year royalty holiday or 283,000,000 m3

of royalty free gas for deep discovery wells with a true vertical depth greater than 4,000 metres whosesurface locations are at least 20 kilometres away from the surface location of any well drilled into arecognized pool within the same formation;

Š Coalbed Gas Royalty Reduction and Credit Program providing a royalty reduction for coalbed gas wellswith average daily production less than 17,000 m3 as well as a royalty credit for coalbed gas wells equal to$50,000 for wells drilled on Crown land and a tax credit equal to $30,000 for wells drilled on freehold land;

Š Marginal Royalty Reduction Program providing royalty breaks for low productivity natural gas wells withaverage monthly production under 25,000 m3 during the first 12 production months and average dailyproduction less than 23 m3 for every metre of marginal well depth;

Š Ultra-Marginal Royalty Reduction Program providing additional royalty breaks for low productivity shallownatural gas wells with a true vertical depth of less than 2,300 metres, average monthly production under60,000 m3 during the first 12 production months and average daily production less than 11.5 m3

(development wells) or 17 m3 (exploratory wildcat wells) for every 100 metres of marginal well depth; and

Š Net Profit Royalty Reduction Program providing reduced initial royalty rates to facilitate the developmentand commercialization of technically complex resources such as coalbed gas, tight gas, shale gas andenhanced-recovery projects, with higher royalty rates applied once capital costs have been recovered.

Oil produced from an oil well event on either Crown or freehold land and completed in a new pool discoverysubsequent to June 30, 1974 may also be exempt from the payment of a royalty for the first 36 months of production or11,450 m3 of production, whichever comes first.

On March 2, 2009, the Government of British Columbia announced the 2009 Infrastructure Royalty CreditProgram (the “Infrastructure Royalty Credit Program”) which allocates $120 million in royalty credits for oil andgas companies. The Infrastructure Royalty Credit Program provides royalty credits for up to 50% of the cost of certainapproved road construction or pipeline infrastructure projects intended to improve, or make possible, the access to newand underdeveloped oil and gas areas. On March 10, 2010, the Government of British Columbia announced the samelevel of funding for the 2010 Infrastructure Royalty Credit Program.

On August 6, 2009, the Government of British Columbia announced an oil and gas stimulus package designed toattract investment in and create economic benefits for British Columbia. The stimulus package includes four royaltyinitiatives related primarily to natural gas drilling and infrastructure development. Natural gas wells spudded within the10-month period from September 1, 2009 to June 30, 2010 and brought on production by December 31, 2010 qualifyfor a 2% royalty rate for the first 12 months of production, beginning from the first month of production for the well(the “Royalty Relief Program”). British Columbia’s existing Deep Royalty Credit Program was permanently amendedfor wells spudded after August 31, 2009 by increasing the royalty deduction on deep drilling for natural gas by 15%and extending the program to include horizontal wells drilled to depths of between 1,900 and 2,300 metres. Wells spudbetween September 1, 2009 and June 30, 2010 may qualify for both the Royalty Relief Program and the Deep RoyaltyCredit Program but will only receive the benefits of one program at a time. An additional $50 million was alsoallocated to be distributed through the Infrastructure Royalty Credit Program to stimulate investment in oilfield-relatedroad and pipeline construction.

Land Tenure

Crude oil and natural gas located in the western provinces is owned predominantly by the respective provincialgovernments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases,licences, and permits for varying terms from two years and on conditions set forth in provincial legislation includingrequirements to perform specific work or make payments. Oil and natural gas located in such provinces can also beprivately owned and rights to explore for and produce such oil and natural gas are granted by lease on such terms andconditions as may be negotiated.

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Each of the provinces of Alberta and British Columbia has implemented legislation providing for the reversion tothe Crown of mineral rights to deep, non-productive geological formations at the conclusion of the primary term of alease or license. On March 29, 2007, British Columbia’s policy of deep rights reversion was expanded for new leasesto provide for the reversion of both shallow and deep formations that cannot be shown to be capable of production atthe end of their primary term.

In Alberta, the NRF includes a policy of “shallow rights reversion” which provides, for the first time in westernCanada, for the reversion to the Crown of mineral rights to shallow, non-productive geological formations for all leasesand licenses. For leases and licenses issued subsequent to January 1, 2009, shallow rights reversion will be applied at theconclusion of the primary term of the lease or license. Holders of leases or licences that have been continued indefinitelyprior to January 1, 2009 will receive a notice regarding the reversion of the shallow rights, which will be implementedthree years from the date of the notice. The order in which these agreements will receive the reversion notice will dependon their vintage and location, with the older leases and licenses receiving reversion notices first beginning in January2011. Leases and licences that were granted prior to January 1, 2009 but continued after that date will not be subject toshallow rights reversion until they reach the end of their primary term and are continued (at which time deep rightsreversion will be applied); thereafter, the holders of such agreements will be served with shallow rights reversion noticesbased on vintage and location similar to leases and licences that were already continued as of January 1, 2009.

Environmental Regulation

The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety ofprovincial and federal legislation. Such legislation provides for restrictions and prohibitions on the release or emissionof various substances produced in association with certain oil and gas industry operations, such as sulphur dioxide andnitrous oxide. In addition, such legislation requires that well and facility sites be abandoned and reclaimed to thesatisfaction of provincial authorities. Compliance with such legislation can require significant expenditures and abreach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civilliability for pollution damage, and the imposition of material fines and penalties.

In December 2008, the Government of Alberta released a new land use policy for surface land in Alberta, theAlberta Land Use Framework (the “ALUF”). The ALUF sets out an approach to manage public and private land useand natural resource development in a manner that is consistent with the long-term economic, environmental and socialgoals of the province. It calls for the development of region-specific land use plans in order to manage the combinedimpacts of existing and future land use within a specific region and the incorporation of a cumulative effectsmanagement approach into such plans. The Alberta Land Stewardship Act (the “ALSA”) was proclaimed in force inAlberta on October 1, 2009, providing the legislative authority for the Government of Alberta to implement the policiescontained in the ALUF. Regional plans established pursuant to the ALSA are deemed to be legislative instrumentsequivalent to regulations and are binding on the Government of Alberta and provincial regulators, including thosegoverning the oil and gas industry. In the event of a conflict or inconsistency between a regional plan and anotherregulation, regulatory instrument or statutory consent, the regional plan will prevail. Further, the ALSA requires localgovernments, provincial departments, agencies and administrative bodies or tribunals to review their regulatoryinstruments and make any appropriate changes to ensure that they comply with an adopted regional plan. The ALSAalso contemplates the amendment or extinguishment of previously issued statutory consents such as regulatory permits,licenses, approvals and authorizations in order for the purpose of achieving or maintaining an objective or policyresulting from the implementation of a regional plan. Among the measures to support the goals of the regional planscontained in the ALSA are conservation easements, which can be granted for the protection, conservation andenhancement of land; and conservation directives, which are explicit declarations contained in a regional plan to setaside specified lands in order to protect, conserve, manage and enhance the environment. Although no regional planshave been established under the ALSA, the planning process is underway for the Lower Athabasca Region (whichcontains the majority of oil sands development) and the South Saskatchewan Region. While the potential impact of theregional plans established under the ALSA cannot yet be determined, it is clear that such regional plans may have asignificant impact on land use in Alberta and may affect the oil and gas industry.

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Climate Change Regulation

Federal

In December 2002, the Government of Canada ratified the Kyoto Protocol (“Kyoto Protocol”), which requires areduction in GHG emissions by signatory countries between 2008 and 2012. The Kyoto Protocol officially came intoforce on February 16, 2005 and commits Canada to reduce its GHG emissions levels to 6% below 1990“business-as-usual” levels by 2012.

In anticipation of the end of the first commitment period under the Kyoto Protocol in 2012, government leadersand representatives from approximately 170 countries met in Copenhagen, Denmark from December 7 through 18,2009 (the “Copenhagen Conference”) to attempt to negotiate a successor to the Kyoto Protocol. The primary result ofthe Copenhagen Conference was the Copenhagen Accord, which represents a broad political consensus rather than abinding international treaty like the Kyoto Protocol and has not been endorsed by all participating countries. TheCopenhagen Accord reinforces the commitment to reducing GHG emissions contained in the Kyoto Protocol andpromises funding to help developing countries mitigate and adapt to climate change. Although certain countries,including Canada, have committed to reducing their emissions individually or jointly by at least 80% by 2050, theCopenhagen Accord does not establish binding GHG emissions reduction targets. The Copenhagen Accord calls for areview and implementation of its stated goals by 2016.

In response to the Copenhagen Accord, the Government of Canada indicated on January 29, 2010 that it will seekto achieve a 17% reduction in GHG emissions from 2005 levels by 2020. This goal matches the goal expressed by theUnited States government.

On February 14, 2007, the House of Commons passed Bill C-288, An Act to ensure Canada meets its globalclimate change obligations under the Kyoto Protocol. The resulting Kyoto Protocol Implementation Act came intoforce on June 22, 2007. Its stated purpose is to “ensure that Canada takes effective and timely action to meet itsobligations under the Kyoto Protocol and help address the problem of global climate change.” It requires the federalMinister of the Environment to, among other things, produce an annual climate change plan detailing the measures tobe taken to ensure Canada meets its obligations under the Kyoto Protocol. It also authorizes the establishment ofregulations respecting matters such as emissions limits, monitoring, trading and enforcement.

On April 26, 2007, the Government of Canada released “Turning the Corner: An Action Plan to Reduce GreenhouseGases and Air Pollution” (the “Action Plan”) which set forth a plan for regulations to address both GHG and airpollution. An update to the Action Plan, “Turning the Corner: Regulatory Framework for Industrial Greenhouse GasEmissions” was released on March 10, 2008 (the “Updated Action Plan”). Although draft regulations for theimplementation of the Updated Action Plan were intended to be published in the fall of 2008 and become binding onJanuary 1, 2010, no such regulations have been proposed to date. Further, representatives of the Government of Canadahave recently indicated that the proposals contained in the Updated Action Plan will be modified to ensure consistencywith the direction ultimately taken by the United States with respect to GHG emissions regulation, which may include anabsolute cap on emissions combined with allowances to be used for compliance that may be partially auctioned off toregulated entities. It is also unclear whether the approach adopted by the United States will provide for the payment into atechnology fund as a compliance mechanism, as is currently permitted in Alberta and by the Updated Action Plan. As aresult, many provisions of the Updated Action Plan, described below, are expected to be significantly modified.

The stated goal of the Updated Action Plan, as currently drafted, is to reduce GHG emissions to 20% below 2006levels by 2020 and 60-70% by 2050. As noted above, the goal has now been modified by the Government of Canada.The Updated Action Plan outlines emissions intensity-based targets which will be applied to regulated sectors on eithera facility-specific, sector-wide or company-by-company basis. Facility-specific targets apply to the upstream oil andgas, oil sands, petroleum refining and natural gas pipelines sectors. Unless a minimum regulatory threshold applies, allfacilities within a regulated sector will be subject to the emissions intensity targets.

The Updated Action Plan makes a distinction between “Existing Facilities” and “New Facilities”. For ExistingFacilities, the Updated Action Plan requires an emissions intensity reduction of 18% below 2006 levels by 2010followed by a continuous annual emissions intensity improvement of 2%. “New Facilities” are defined as facilitiesbeginning operations in 2004 and include both greenfield facilities and major facility expansions that (i) result in a 25%or greater increase in a facility’s physical capacity, or (ii) involve significant changes to the processes of the facility.New Facilities will be given a 3-year grace period during which no emissions intensity reductions will be required.

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Targets requiring an annual 2% emissions intensity reduction will begin to apply in the fourth year of commercialoperation of a New Facility. Further, emissions intensity targets for New Facilities will be based on a cleaner fuelstandard to encourage continuous emissions intensity reductions over time. The method of applying this cleaner fuelstandard has not yet been determined. In addition, the Updated Action Plan indicates that targets for the adoption ofcarbon capture and storage (“CCS”) technologies will be developed for oil sands in-situ facilities, upgraders and coal-fired power generators that begin operations in 2012 or later. These targets will become operational in 2018, althoughthe exact nature of the targets has not yet been determined.

Given the large number of small facilities within the upstream oil and gas and natural gas pipeline sectors,facilities within these sectors will only be subject to emissions intensity targets if they meet certain minimum emissionsthresholds. That threshold will be: (i) 50,000 tonnes of CO2 equivalents per facility per year for natural gas pipelines;(ii) 3,000 tonnes of CO2 equivalents per facility per year for the upstream oil and gas facility; and (iii) 10,000 Boe/d/company. These regulatory thresholds are significantly lower than the regulatory threshold in force in Alberta,discussed below.

Four separate compliance mechanisms are provided for in the Updated Action Plan in respect of the above targets:Technology Fund contributions, offset credits, clean development credits and credits for early action. Regulatedentities will be able to use Technology Fund contributions to meet their emissions intensity targets. The contributionrate for Technology Fund contributions will increase over time, beginning at $15 tonnes per CO2 equivalent for the2010-12 period, rising to $20 in 2013, and thereafter increasing at the nominal rate of GDP growth. Maximumcontribution limits will also decline from 70% in 2010 to 0% in 2018. Monies raised through contributions to theTechnology Fund will be used to invest in technology to reduce GHG emissions. Alternatively, regulated entities maybe able to receive credits for investing in large-scale and transformative projects at the same contribution rate andunder similar requirements as described above.

The offset system is intended to encourage emissions reductions from activities outside of the regulated sphere,allowing non-regulated entities to participate in and benefit from emissions reduction activities. In order to generateoffset credits, project proponents must propose and receive approval for emissions reduction activities that will beverified before offset credits will be issued to the project proponent. Those credits can then be sold to regulated entitiesfor use in compliance or non-regulated purchasers that wish to either purchase the offset credits for cancellation orbanking for future use or sale.

Under the Updated Action Plan, regulated entities will also be able to purchase credits created through the CleanDevelopment Mechanism of the Kyoto Protocol which facilitates investment by developed nations in emissions-reduction projects in developing countries. The purchase of such Emissions Reduction Credits will be restricted to 10%of each firm’s regulatory obligation, with the added restriction that credits generated through forest sink projects willnot be available for use in complying with the Canadian regulations.

Finally, a one-time credit of up to 15 million tonnes worth of emissions credits will be awarded to regulated entitiesfor emissions reduction activities undertaken between 1992 and 2006. These credits will be both tradable and bankable.

Alberta

Alberta enacted the Climate Change and Emissions Management Act (the “CCEMA”) on July 1, 2007, amendingit through the Climate Change and Emissions Management Amendment Act which received royal asset on November 4,2008. The CCEMA is based on an emissions intensity approach similar to the Updated Action Plan and aims for a 50%reduction from 1990 emissions relative to gross domestic product by 2020.

Alberta facilities emitting more than 100,000 tonnes of GHG a year are subject to comply with the CCEMA.Similar to the Updated Action Plan, the CCEMA and the associated Specified Gas Emitters Regulation make adistinction between “Existing Facilities” and “New Facilities”. Existing Facilities are defined as facilities thatcompleted their first year of commercial operation prior to January 1, 2008 or that have completed eight or more yearsof commercial operation. Existing Facilities are required to reduce their emissions intensity by March 31, 2008 by 12%from a baseline established by their average emissions intensity between 2003 and 2005. New Facilities are defined asfacilities that completed their first year of commercial operation subsequent to December 31, 2008, have completedless than eight years of commercial operation, or are designated as New Facilities in accordance with the Specified GasEmitters Regulation. New Facilities are also required to reduce their emissions intensity by 12% but this target is based

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on the emissions intensity of the facility in its third year of commercial operation and does not apply during the firstthree years of operation of the New Facility. Unlike the Updated Action Plan, the CCEMA does not contain anyprovision for continuous annual improvements beyond the 12% emissions intensity required.

The CCEMA contains similar compliance mechanisms as the Updated Action Plan. Regulated emitters can meettheir emissions intensity targets by contributing to the Climate Change and Emissions Management Fund (the “Fund”)at a rate of $15 per tonne of CO2 equivalent. Unlike the Updated Action Plan, CCEMA contains no provisions for anincrease to this contribution rate. Emissions credits can be purchased from regulated emitters that have reduced theiremissions below the 100,000 tonne threshold or non-regulated emitters that have generated emissions offsets throughactivities that result in emissions reductions in accordance with established protocols published by the Government ofAlberta. Unlike the Updated Action Plan, the CCEMA does not contemplate a linkage to external compliancemechanisms such as the Kyoto Protocol’s Clean Development Mechanism.

British Columbia

In February, 2008, British Columbia announced a revenue-neutral carbon tax that took effect July 1, 2008. The taxis consumption-based and applied at the time of retail sale or consumption of virtually all fossil fuels purchased or usedin British Columbia. The initial level of the tax was set at $10 per tonne of CO2 equivalent and rose to $15 per tonne ofCO2 equivalent on July 1, 2009 and $20 per tonne of CO2 equivalent on July 1, 2010. It is scheduled to further increaseat a rate of $5 per tonne of CO2 equivalent on July 1 of every year until it reaches $30 per tonne of CO2 equivalent onJuly 31, 2012. In order to make the tax revenue-neutral, British Columbia has implemented tax credits and reductionsin order to offset the tax revenues that the Government of British Columbia would otherwise receive from the tax.

On April 3, 2008, British Columbia introduced the Greenhouse Gas Reduction (Cap and Trade) Act (the “Capand Trade Act”) which received royal assent on May 29, 2008 and will come into force by regulation of theLieutenant Governor in Council. Unlike the emissions intensity approach taken by the federal government and theGovernment of Alberta, the Cap and Trade Act establishes an absolute cap on GHG emissions and is designed toenable the province to participate in the Western Climate’s cap-and-trade system. It is expected that GHG emissionsrestrictions will be applied to facilities emitting more than 25,000 tonnes of CO2 equivalents per year, which will berequired to meet established targets through a combination of emissions allowances issued by the Government ofBritish Columbia and the purchase of emissions offsets generated through activities that result in a reduction in GHGemissions. Although more specific details of British Columbia’s cap and trade plan have not yet been finalized, onJanuary 1, 2010, new reporting regulations came into force requiring all British Columbia facilities emitting over10,000 tonnes of CO2 equivalents per year to begin reporting their emissions. Facilities reporting emissions greaterthan 25,000 tonnes of CO2 equivalents per year are required to have their emissions reports verified by a third-party.Further regulations under the Cap and Trade Act, including regulations with respect to emissions trading and offsets,are currently under consultation and are expected to be finalized in early 2011.

RISK FACTORS

An investment in the Common Shares is speculative and involves a substantial degree of risk that should beconsidered by potential purchasers. A potential purchaser should carefully consider the following risk factors inaddition to the other information contained in this prospectus before purchasing Common Shares. The risks anduncertainties set out below are not the only ones the Company is facing. There are additional risks and uncertaintiesthat the Company does not currently know about or that the Company currently considers immaterial which may alsoimpair the Company’s business operations and cause the price of the Common Shares to decline. If any of thefollowing risks actually occur, the Company’s business may be harmed and the Company’s financial condition andresults of operations may suffer significantly. In that event, the trading price of the Common Shares could decline anda purchaser may lose all or part of the purchaser’s investment.

Risks Related to the Company’s Business

Exploration, Development and Production Risks

Oil and natural gas operations involve many risks that even a combination of experience, knowledge and carefulevaluation may not be able to overcome. The long-term commercial success of the Company depends on its ability tofind, acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new

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reserves, any existing reserves the Company may have at any particular time, and the production therefrom, willdecline over time as such existing reserves are exploited. A future increase in the Company’s reserves will depend notonly on its ability to explore and develop any properties it may have from time to time, but also on its ability to selectand acquire suitable producing properties or prospects. No assurance can be given that the Company will be able tocontinue to locate satisfactory properties for acquisition or participation. Moreover, if such acquisitions orparticipations are identified, management of the Company may determine that current markets, terms of acquisitionand participation or pricing conditions make such acquisitions or participations uneconomic. There is no assurance thatfurther commercial quantities of oil and natural gas will be discovered or acquired by the Company.

Future oil and natural gas exploration may involve unprofitable efforts, not only from dry holes, but also fromwells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, operatingand other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion andoperating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations,and various field operating conditions may adversely affect the production from successful wells. These conditionsinclude delays in obtaining governmental approvals or consents, shut-in of connected wells resulting from extremeweather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions.While diligent well supervision and effective maintenance operations can contribute to maximizing production ratesover time, production delays and declines from normal field operating conditions cannot be eliminated and can beexpected to adversely affect revenue and cash flow levels to varying degrees.

Oil and natural gas exploration, development and production operations are subject to all the risks and hazardstypically associated with such operations, including hazards such as fire, explosion, blowouts, cratering, sour gasreleases and spills, each of which could result in substantial damage to oil and natural gas wells, production facilities,other property and the environment or personal injury. In particular, the Company may explore for and produce sournatural gas in certain areas. An unintentional leak of sour natural gas could result in personal injury, loss of life ordamage to property and may necessitate an evacuation of populated areas, all of which could result in liability to theCompany. In accordance with industry practice, the Company is not fully insured against all of these risks, nor are allsuch risks insurable. Although the Company maintains liability insurance in an amount that it considers consistent withindustry practice, the nature of these risks is such that liabilities could exceed policy limits, in which event theCompany could incur significant costs. Oil and natural gas production operations are also subject to all the riskstypically associated with such operations, including encountering unexpected formations or pressures, prematuredecline of reservoirs and the invasion of water into producing formations. Losses resulting from the occurrence of anyof these risks may have a material adverse effect on the Company’s business, financial condition, results of operationsand prospects.

Global Financial Crisis

Recent market events and conditions, including disruptions in the international credit markets and other financialsystems and the deterioration of global economic conditions, have caused significant volatility to commodity prices.These conditions worsened in 2008 and continued in 2009, causing a loss of confidence in the broader U.S. and globalcredit and financial markets and resulting in the collapse of, and government intervention in, major banks, financialinstitutions and insurers and creating a climate of greater volatility, less liquidity, widening of credit spreads, a lack ofprice transparency, increased credit losses and tighter credit conditions. Notwithstanding various actions bygovernments, concerns about the general condition of the capital markets, financial instruments, banks, investmentbanks, insurers and other financial institutions caused the broader credit markets to further deteriorate and stockmarkets to decline substantially. These factors have negatively impacted company valuations and may impact theperformance of the global economy going forward. Although economic conditions improved towards the latter portionof 2009, the recovery from the recession has been slow in certain jurisdictions including in Europe and the UnitedStates and has been affected by various factors including sovereign debt levels and high levels of unemployment whichcontinue to affect commodity prices and stock market volatility.

Prices, Markets and Marketing

The marketability and price of oil and natural gas that may be acquired or discovered by the Company is and willcontinue to be affected by numerous factors beyond its control. The Company’s ability to market its oil and natural gasmay depend upon its ability to acquire space on pipelines that deliver natural gas to commercial markets. The Companymay also be affected by deliverability uncertainties related to the proximity of its reserves to pipelines and processing

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and storage facilities and operational problems affecting such pipelines and facilities, as well as extensive governmentregulation relating to price, taxes, royalties, land tenure, allowable production, the export of oil and natural gas andmany other aspects of the oil and gas business.

The prices of oil and natural gas prices may be volatile and subject to fluctuation. Any material decline in pricescould result in a reduction of the Company’s net production revenue. The economics of producing from some wellsmay change as a result of lower prices, which could result in reduced production of oil or natural gas and a reduction inthe volumes of the Company’s reserves. The Company might also elect not to produce from certain wells at lowerprices. All of these factors could result in a material decrease in the Company’s expected net production revenue and areduction in its oil and gas acquisition, development and exploration activities. Prices for oil and gas are subject tolarge fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, marketuncertainty and a variety of additional factors beyond the control of the Company. These factors include economicconditions, in the United States and Canada, the actions of the Organization of Petroleum Exporting Countries(“OPEC”), governmental regulation, political stability in the Middle East and elsewhere, the foreign supply of oil andgas, risks of supply disruption, the price of foreign imports and the availability of alternative fuel sources. Anysubstantial and extended decline in the price of oil and gas would have an adverse effect on the Company’s carryingvalue of its reserves, borrowing capacity, revenues, profitability and cash flows from operations and may have amaterial adverse effect on the Company’s business, financial condition, results of operations and prospects.

Petroleum prices are expected to remain volatile for the near future as a result of market uncertainties over thesupply and the demand of these commodities due to the current state of the world economies, OPEC actions and theongoing credit and liquidity concerns. Volatile oil and gas prices make it difficult to estimate the value of producingproperties for acquisition and often cause disruption in the market for oil and gas producing properties, as buyers andsellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the returnon acquisitions and development and exploitation projects.

In addition, bank borrowings available to the Company may, in part, be determined by the Company’s borrowingbase. A sustained material decline in prices from historical average prices could reduce the Company’s borrowing base,therefore reducing the bank credit available to the Company which could require that a portion, or all, of theCompany’s bank debt be repaid.

Failure to Realize Anticipated Benefits of Acquisitions and Dispositions

The Company makes acquisitions and dispositions of businesses and assets in the ordinary course of business.Achieving the benefits of acquisitions depends, in part, on successfully consolidating functions and integratingoperations and procedures in a timely and efficient manner, as well as the Company’s ability to realize the anticipatedgrowth opportunities and synergies from combining the acquired businesses and operations with those of the Company.The integration of acquired business may require substantial management effort, time and resources and may divertmanagement’s focus from other strategic opportunities and operational matters. Assets determined by management tobe “non-core” are periodically disposed of, so that the Company can focus its efforts and resources more efficiently.Depending on the state of the market for such non-core assets, certain non-core assets of the Company, if disposed of,could be expected to realize less than their carrying value on the financial statements of the Company.

Future Acquisition Activities May Have Adverse Effects

The acquisition of oil and natural gas companies and assets is subject to substantial risks, including the failure toidentify material problems during due diligence, the risk of over-paying for assets and the inability to arrange financingfor an acquisition as may be required or desired. Further, the integration and consolidation of acquisitions requiressubstantial human, financial and other resources and, ultimately, the Company’s acquisitions may not be successfullyintegrated. There can be no assurances that any future acquisitions will perform as expected or that the returns from suchacquisitions will support the indebtedness incurred to acquire them or the capital expenditures needed to develop them.

Operational Dependence

Other companies operate some of the assets in which the Company has an interest. As a result, the Company haslimited ability to exercise influence over the operation of those assets or their associated costs, which could adverselyaffect the Company’s financial performance. The Company’s return on assets operated by others therefore depends

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upon a number of factors that may be outside of the Company’s control, including the timing and amount of capitalexpenditures, the operator’s expertise and financial resources, the approval of other participants, the selection oftechnology and risk management practices.

Project Risks

The Company manages a variety of small and large projects in the conduct of its business. Project delays maydelay expected revenues from operations. Significant project cost over-runs could make a project uneconomic. TheCompany’s ability to execute projects and market oil and natural gas depends upon numerous factors beyond theCompany’s control, including: the availability of processing capacity; the availability and proximity of pipelinecapacity; the availability of storage capacity; the supply of and demand for oil and natural gas; the availability ofalternative fuel sources; the effects of inclement weather; the availability of drilling and related equipment; unexpectedcost increases; accidental events; currency fluctuations; changes in regulations; the availability and productivity ofskilled labour; and the regulation of the oil and natural gas industry by various levels of government and governmentalagencies.

As a result of these factors, the Company could be unable to execute projects on time, on budget or at all, and maynot be able to effectively market the oil and natural gas that it produces.

Competition

The petroleum industry is competitive in all its phases. The Company competes with numerous otherorganizations in the search for, and the acquisition of, oil and natural gas properties and in the marketing of oil andnatural gas. The Company’s competitors include oil and natural gas companies that have substantially greater financialresources, staff and facilities than those of the Company. The Company’s ability to increase its reserves in the futurewill depend not only on its ability to explore and develop its present properties, but also on its ability to select andacquire other suitable producing properties or prospects for exploratory drilling. Competitive factors in the distributionand marketing of oil and natural gas include price and methods and reliability of delivery and storage. Competitionmay also be presented by alternate fuel sources.

Regulatory

Oil and natural gas operations (exploration, development, production, pricing, marketing and transportation) aresubject to extensive controls and regulations imposed by various levels of government, which may be amended fromtime to time. See “Industry Conditions”. Governments may regulate or intervene with respect to price, taxes, royaltiesand the exportation of oil and natural gas. Such regulations may be changed from time to time in response to economicor political conditions. The implementation of new regulations or the modification of existing regulations affecting theoil and natural gas industry could reduce demand for natural gas and crude oil and increase the Company’s costs, anyof which may have a material adverse effect on the Company’s business, financial condition, results of operations andprospects. In order to conduct oil and gas operations, the Company will require licenses from various governmentalauthorities. There can be no assurance that the Company will be able to obtain all of the licenses and permits that maybe required to conduct operations that it may wish to undertake.

Environmental

All phases of the oil and natural gas business present environmental risks and hazards and are subject toenvironmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Environmentallegislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of varioussubstances produced in association with oil and natural gas operations. The legislation also requires that wells andfacility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities.Compliance with such legislation can require significant expenditures and a breach of applicable environmentallegislation may result in the imposition of fines and penalties, some of which may be material. Environmentallegislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liabilityand potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutantsinto the air, soil or water may give rise to liabilities to governments and third parties and may require the Company toincur costs to remedy such discharge. Although the Company believes that it currently is and will continue to be inmaterial compliance with current applicable environmental regulations, no assurance can be given that future

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environmental laws will not result in a curtailment of production or a material increase in the costs of production,development or exploration activities or otherwise have a material adverse effect on the Company’s business, financialcondition, results of operations and prospects.

Climate Change

Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the KyotoProtocol established thereunder to set legally binding targets to reduce nationwide emissions of carbon dioxide,methane, nitrous oxide and other so-called “greenhouse gases” or GHG. Late in 2009, representatives fromapproximately 170 countries met in Copenhagen, Denmark to attempt to negotiate a successor to the Kyoto Protocol.Pursuant to the resulting Copenhagen Accord, which is a non-binding political consensus rather than a bindinginternational treaty such as the Kyoto Protocol, the Government of Canada revised its emissions reduction target. TheCanadian target is now a 17% reduction in GHG emissions from 2005 levels by the year 2020. There has been muchpublic debate with respect to Canada’s ability to meet this target and the Government’s strategy or alternative strategieswith respect to climate change and the control of GHG.

The Company’s exploration and production facilities and other operations and activities emit GHG and require theCompany to comply with Alberta’s GHG emissions legislation contained in the CCEMA and the Specified GasEmitters Regulation. The Company may also be required to comply with the regulatory scheme for GHG emissionsultimately adopted by the federal government, which is now expected to be modified to ensure consistency with theregulatory scheme for GHG emissions adopted by the United States. The direct or indirect costs of these regulationsmay have a material adverse effect on the Company’s business, financial condition, results of operations and prospects.The future implementation or modification of GHG regulations, whether to meet the limits required by the KyotoProtocol, the Copenhagen Accord or as otherwise determined, could have a material impact on the nature of oil andnatural gas operations, including those of the Company. Given the evolving nature of the debate related to climatechange and the control of GHG and resulting requirements, it is not possible to predict the impact on the Company andits operations and financial condition. See “Industry Conditions – Climate Change Regulation”.

Variations in Foreign Exchange Rates and Interest Rates

World oil and gas prices are quoted in United States dollars and the price received by Canadian producers istherefore affected by the Canadian/U.S. dollar exchange rate, which fluctuates over time. In recent years, the Canadiandollar has increased materially in value against the United States dollar. Material increases in the value of the Canadiandollar negatively impact the Company’s production revenues. Future Canadian/U.S. dollar exchange rates couldaccordingly impact the future value of the Company’s reserves as determined by independent evaluators.

To the extent that the Company engages in risk management activities related to foreign exchange rates, there is acredit risk associated with counterparties with which the Company may contract.

An increase in interest rates could result in a significant increase in the amount the Company pays to service debt,which could negatively impact the market price of the Common Shares of the Company.

Substantial Capital Requirements

The Company anticipates making substantial capital expenditures for the acquisition, exploration, developmentand production of oil and natural gas reserves in the future. If the Company’s revenues or reserves decline, it may nothave access to the capital necessary to undertake or complete future drilling programs. In addition, uncertain levels ofnear term industry activity coupled with uncertainty in domestic and international credit markets exposes the Companyto additional access to capital risk. There can be no assurance that debt or equity financing, or cash generated byoperations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equityfinancing is available, that it will be on terms acceptable to the Company. The inability of the Company to accesssufficient capital for its operations could have a material adverse effect on the Company’s business financial condition,results of operations and prospects.

Additional Funding Requirements

The Company’s cash flow from its reserves may not be sufficient to fund its ongoing activities at all times. Fromtime to time, the Company may require additional financing in order to carry out its oil and gas acquisition, exploration

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and development activities. Failure to obtain such financing on a timely basis could cause the Company to forfeit itsinterest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations. If theCompany’s revenues from its reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affectthe Company’s ability to expend the necessary capital to replace its reserves or to maintain its production. If theCompany’s cash flow from operations is not sufficient to satisfy its capital expenditure requirements, there can be noassurance that additional debt or equity financing will be available to meet these requirements or, if available, on termsacceptable to the Company. Continued uncertainty in domestic and international credit markets could materially affectthe Company’s ability to access sufficient capital for its capital expenditures and acquisitions, and as a result, may havea material adverse effect on the Company’s ability to execute its business strategy and on its business, financialcondition, results of operations and prospects.

Issuance of Debt

From time to time the Company may enter into transactions to acquire assets or the shares of other organizations.These transactions may be financed in whole or in part with debt, which may increase the Company’s debt levels aboveindustry standards for oil and natural gas companies of similar size. Depending on future exploration and developmentplans, the Company may require additional equity and/or debt financing that may not be available or, if available, maynot be available on favourable terms. Neither the Company’s articles nor its by-laws limit the amount of indebtednessthat the Company may incur. The level of the Company’s indebtedness from time to time, could impair the Company’sability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise.

Hedging

From time to time the Company may enter into agreements to receive fixed prices on its oil and natural gasproduction to offset the risk of revenue losses if commodity prices decline; however, if commodity prices increasebeyond the levels set in such agreements, the Company will not benefit from such increases and the Company maynevertheless be obligated to pay royalties on such higher prices, even though not received by it, after giving effect tosuch agreements. Similarly, from time to time the Company may enter into agreements to fix the exchange rate ofCanadian to U.S. dollars in order to offset the risk of revenue losses if the Canadian dollar increases in value comparedto the U.S. dollar; however, if the Canadian dollar declines in value compared to the U.S. dollar, the Company will notbenefit from the fluctuating exchange rate.

Internal Controls

Effective internal controls are necessary for the Company to provide reliable financial reports and to help preventfraud. Although the Company undertakes a number of procedures in order to help ensure the reliability of its financialreports, including those imposed on it under Canadian securities laws, the Company cannot be certain that such measureswill ensure that the Company will maintain adequate control over financial processes and reporting. Failure to implementrequired new or improved controls, or difficulties encountered in their implementation, could harm the Company’s resultsof operations or cause it to fail to meet its reporting obligations. If the Company or its independent auditors discover amaterial weakness, the disclosure of that fact, even if quickly remedied, could reduce the market’s confidence in theCompany’s consolidated financial statements and adversely affect the trading price of the Common Shares.

Availability of Drilling Equipment and Access

Oil and natural gas exploration and development activities are dependent on the availability of drilling and relatedequipment (typically leased from third parties) in the particular areas where such activities will be conducted. Demandfor such limited equipment or access restrictions may affect the availability of such equipment to the Company andmay delay exploration and development activities.

Title to Assets

Although title reviews may be conducted prior to the purchase of oil and natural gas producing properties or thecommencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of titlewill not arise to defeat the Company’s claim which may have a material adverse effect on the Company’s business,financial condition, results of operations and prospects.

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Reserve Estimates

There are numerous uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and thefuture cash flows attributed to such reserves. The reserve and associated cash flow information set forth in thisprospectus are estimates only. In general, estimates of economically recoverable oil and natural gas reserves and thefuture net cash flows therefrom are based upon a number of variable factors and assumptions, such as historicalproduction from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures,marketability of oil and gas, royalty rates, the assumed effects of regulation by governmental agencies and futureoperating costs, all of which may vary materially from actual results. For those reasons, estimates of the economicallyrecoverable oil and natural gas reserves attributable to any particular group of properties, classification of such reservesbased on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers,or by the same engineers at different times, may vary. The Company’s actual production, revenues, taxes anddevelopment and operating expenditures with respect to its reserves will vary from estimates thereof and suchvariations could be material.

Estimates of proved reserves that may be developed and produced in the future are often based upon volumetriccalculations and upon analogy to similar types of reserves rather than actual production history. Recovery factors anddrainage areas are estimated by experience and analogy to similar producing pools. Estimates based on these methodsare generally less reliable than those based on actual production history. Subsequent evaluation of the same reservesbased upon production history and production practices will result in variations in the estimated reserves and suchvariations could be material.

In accordance with applicable securities laws, the Company’s independent reserves evaluators have used forecastprices and costs in estimating the reserves and future net cash flows as summarized in this prospectus. Actual future netcash flows will be affected by other factors, such as actual production levels, supply and demand for oil and naturalgas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation ortaxation and the impact of inflation on costs.

Actual production and cash flows derived from the Company’s oil and gas reserves will vary from the estimatescontained in the Reserve Reports, the Sproule Altia Reserve Report and the AJM Greater Hinton Reserve Report andsuch variations could be material. The Reserve Reports, the Sproule Altia Reserve Report and the AJM Greater HintonReserve Report are based in part on the assumed success of activities the Company intends to undertake in future years.The reserves and estimated cash flows to be derived therefrom contained in the Reserve Reports, the Sproule AltiaReserve Report and the AJM Greater Hinton Reserve Report will be reduced to the extent that such activities do notachieve the level of success assumed in the Reserve Reports, the Sproule Altia Reserve Report and the AJM GreaterHinton Reserve Report. The Reserve Reports, the Sproule Altia Reserve Report and the AJM Greater Hinton ReserveReport are effective as of a specific effective date and have not been updated and thus do not reflect changes in theCompany’s reserves since those dates.

Insurance

The Company’s involvement in the exploration for and development of oil and natural gas properties may result inthe Company becoming subject to liability for pollution, blowouts, leaks of sour natural gas, property damage, personalinjury or other hazards. Although the Company maintains insurance in accordance with industry standards to addresscertain of these risks, such insurance has limitations on liability and may not be sufficient to cover the full extent ofsuch liabilities. In addition, such risks are not, in all circumstances, insurable or, in certain circumstances, the Companymay elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance orother reasons. The payment of any uninsured liabilities would reduce the funds available to the Company. Theoccurrence of a significant event that the Company is not fully insured against, or the insolvency of the insurer of suchevent, may have a material adverse effect on the Company’s business, financial condition, results of operations andprospects.

Litigation Risks

In the normal course of the Company’s operations, it may become involved in, named as a party to, or be thesubject of, various legal proceedings, including regulatory proceedings, tax proceedings and legal actions, relating topersonal injuries, property damage, property taxes, land rights, the environment and contract disputes. The outcome of

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outstanding, pending or future proceedings cannot be predicted with certainty and may be determined adversely to theCompany and as a result, could have a material adverse effect on the Company’s assets, liabilities, business, financialcondition and results of operations. Even if the Company prevails in any such legal proceeding, the proceedings couldbe costly and time-consuming and may divert the attention of management and key personnel from the Company’sbusiness operations, which could adversely affect its financial condition.

Geo-Political Risks

The marketability and price of oil and natural gas that may be acquired or discovered by the Company is and willcontinue to be affected by political events throughout the world that cause disruptions in the supply of oil. Conflicts, orconversely peaceful developments, arising in the Middle-East, and other areas of the world, have a significant impacton the price of oil and natural gas. Any particular event could result in a material decline in prices and therefore resultin a reduction of the Company’s net production revenue.

In addition, the Company’s oil and natural gas properties, wells and facilities could be subject to a terrorist attack.If any of the Company’s properties, wells or facilities are the subject of terrorist attack it may have a material adverseeffect on the Company’s business, financial condition, results of operations and prospects. The Company will not haveinsurance to protect against the risk from terrorism.

Management of Growth

The Company may be subject to growth-related risks including capacity constraints and pressure on its internalsystems and controls. The ability of the Company to manage growth effectively will require it to continue to implementand improve its operational and financial systems and to expand, train and manage its employee base. The inability ofthe Company to property manage growth may have a material adverse effect on the Company’s business, financialcondition, results of operations and prospects.

Expiration of Licences and Leases

The Company’s properties are held in the form of licences and leases and working interests in licences and leases.If the Company or the holder of the licence or lease fails to meet the specific requirement of a licence or lease, thelicence or lease may terminate or expire. There can be no assurance that any of the obligations required to maintaineach licence or lease will be met. The termination or expiration of the Company’s licences or leases or the workinginterests relating to a licence or lease may have a material adverse effect on the Company’s business, financialcondition, results of operations and prospects.

Aboriginal Claims

Aboriginal peoples have claimed aboriginal title and rights to portions of western Canada. The Company is notaware that any claims have been made in respect of its properties and assets; however, if a claim arose and wassuccessful such claim may have a material adverse effect on the Company’s business, financial condition, results ofoperations and prospects.

Seasonality

The level of activity in the Canadian oil and gas industry is influenced by seasonal weather patterns. Wet weatherand spring thaw may make the ground unstable. Consequently, municipalities and provincial transportationdepartments enforce road bans that restrict the movement of drilling rigs and other heavy equipment, thereby reducingactivity levels. Also, certain oil and gas producing areas are located in areas that are inaccessible other than during thewinter months because the ground surrounding the sites in these areas consists of swampy terrain. Seasonal factors andunexpected weather patterns may lead to declines in exploration, development and production activity.

Third-Party Credit Risk

The Company may be exposed to third-party credit risk through its contractual arrangements with its current orfuture joint venture partners, marketers of its petroleum and natural gas production and other parties. In the event suchentities fail to meet their contractual obligations to the Company, such failures may have a material adverse effect on

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the Company’s business, financial condition, results of operations and prospects. In addition, poor credit conditions inthe industry and of joint venture partners may impact a joint venture partner’s willingness to participate in theCompany’s ongoing capital program, potentially delaying the program and the results of such program until theCompany finds a suitable alternative partner.

Conflicts of Interest

Certain officers and directors of the Company are also officers and/or directors of other oil and gas companies andas such may, in certain circumstances, have a conflict of interest requiring them to abstain from certain decisions.Conflicts, if any, will be subject to the procedures and remedies of the ABCA. See “Directors and Officers – Conflictsof Interest”.

Reliance on Key Personnel

The Company’s success depends in large measure on certain key personnel including its Chief Executive Officerand its management team. The loss of the services of such key personnel may have a material adverse effect on theCompany’s business, financial condition, results of operations and prospects. The Company does not have any keyperson insurance in effect for the Company. The contributions of the existing management team to the immediate andnear term operations of the Company are likely to be of central importance. In addition, the competition for qualifiedpersonnel in the oil and natural gas industry is intense and there can be no assurance that the Company will be able tocontinue to attract and retain all personnel necessary for the development and operation of its business. Potentialinvestors must rely upon the ability, expertise, judgment, discretion, integrity and good faith of the management of theCompany.

Changes to Accounting Policies, including the Implementation of IFRS

In January 2006, the AcSB adopted a strategic plan for the direction of accounting standards in Canada. As part ofthat plan, the AcSB confirmed in February 2008 that IFRS will replace Canadian GAAP in 2011 for Canadian publiclyaccountable enterprises. While IFRS uses a conceptual framework similar to Canadian GAAP, there are significantdifferences that must be evaluated. The implementation of IFRS may result in significant adjustments to theCompany’s financial results, which could negatively impact the Company’s business, including increasing the risk offailing a financial covenant contained within the Credit Facilities. At this time, Tourmaline cannot reasonably quantifythe full impact that adopting IFRS will have on its financial position and future results.

Forward-Looking Information May Prove Inaccurate

Purchasers are cautioned not to place undue reliance on forward-looking information. By its nature, forward-looking information involves numerous assumptions, known and unknown risks and uncertainties, of both a generaland specific nature, that could cause actual results to differ materially from those suggested by the forward-lookinginformation or contribute to the possibility that predictions, forecasts or projections will prove to be materiallyinaccurate.

Additional information on the risks, assumptions and uncertainties are found in this prospectus under theheading “Forward-Looking Statements”.

Risks Related to the Offering

Absence of a Liquid, Public Market

Before the Offering, there has been no public market for the Common Shares and there can be no assurance that aliquid, public market will develop or, if developed, may not be maintained, for the Common Shares. If an active publicmarket does not develop or is not maintained, investors may have difficulty selling their Common Shares. The OfferingPrice was determined through negotiations between the Company and the Underwriters. Among the factors consideredin determining the Offering Price were the experience of the Company’s management, the Company’s future prospectsand the future prospects of the oil and gas industry in general, the Company’s revenue, earnings and other financial andoperating information in recent periods, the Company’s debt adjusted cash flow multiples, netbacks, project drillinginventory, per flowing Boe metrics and the market prices of securities and certain financial and other operating

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information of companies engaged in activities similar to those of the Company. The Offering Price may not beindicative of the market price for the Common Shares after the Offering, which price may decline below the OfferingPrice. See “Plan of Distribution”.

Share Price Volatility

The market price for Common Shares may be volatile and subject to wide fluctuations in response to numerousfactors, many of which are beyond the Company’s control, including the following: (i) actual or anticipatedfluctuations in the Company’s quarterly results of operations; (ii) actual or anticipated changes in oil and natural gasprices; (iii) recommendations by securities research analysts; (iv) changes in the economic performance or marketvaluations of other companies that investors deem comparable to the Company; (v) addition or departure of theCompany’s executive officers and other key personnel; (ii) sales or perceived sales of additional Common Shares; (vii)significant acquisitions or business combinations, strategic partnerships, joint ventures or capital commitments by orinvolving the Company or its competitors; and (viii) news reports relating to trends, concerns, technological orcompetitive developments, regulatory changes and other related issues in the Company’s industry or target markets.

Financial markets have experienced significant price and volume fluctuations in the last several years that haveparticularly affected the market prices of equity securities of companies and that have, in many cases, been unrelated tothe operating performance, underlying asset values or prospects of such companies. Accordingly, the market price ofthe Common Shares may decline even if the Company’s operating results, underlying asset values or prospects havenot changed. Additionally, these factors, as well as other related factors, may cause decreases in asset values that aredeemed to be other than temporary, which may result in impairment losses. As well, certain institutional investors maybase their investment decisions on consideration of the Company’s environmental, governance and social practices andperformance against such institutions’ respective investment guidelines and criteria, and failure to meet such criteriamay result in a limited or no investment in the Common Shares by those institutions, which could adversely affect thetrading price of the Common Shares. There can be no assurance that continuing fluctuations in the price and volume ofpublicly traded equity securities will not occur. If such increased levels of volatility and market turmoil continue, theCompany’s operations could be adversely impacted and the trading price of the Common Shares may be adverselyaffected.

Discretion in the Use of Proceeds

Management will have broad discretion concerning the use of the proceeds of the Offering, as well as the timingof their expenditure. As a result, purchasers will be relying on the judgment of management for the application of theproceeds of the Offering. Management may use the net proceeds of the Offering in ways that purchasers may notconsider desirable. The results and the effectiveness of the application of the net proceeds are uncertain. If the proceedsare not applied effectively, the results of the Company’s operations may suffer.

Dividends

The Company has never declared or paid any cash dividends on its Common Shares. The Company currentlyintends to retain future earnings, if any, for future operations, expansion and debt repayment. Any decision to declareand pay dividends will be made at the discretion of the Board of Directors and will depend on, among other things, theCompany’s results of operations, current and anticipated cash requirements and surplus, financial condition,contractual restrictions and financing agreement covenants, solvency tests imposed by corporate law and other factorsthat the Board of Directors may consider relevant

In addition to the foregoing, the Company’s ability to institute and pay dividends now or in the future may belimited by covenants contained in the agreements governing any indebtedness that the Company has incurred or mayincur in the future including the terms of the Credit Facilities. The Tourmaline Credit Facility prohibits Tourmalinefrom declaring or paying any dividends (excluding stock dividends) to any of its shareholders or returning any capital(including by way of dividend) to any of its shareholders.

As a result of the foregoing factors, purchasers of Common Shares may not receive any return on an investment inCommon Shares purchased under the Offering unless they sell such Common Shares for a price greater than that whichthey paid for it.

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Dilution and Further Sales

The Company may make future acquisitions or enter into financings or other transactions involving the issuanceof securities of the Company which may be dilutive.

The Company has agreed to refrain from issuing or selling further Common Shares for a period of 180 days afterthe Closing Date without the consent of the Lead Underwriter on behalf of the Underwriters, subject to certainexceptions. However, at the end of that period, there will be no restrictions to the Company issuing or selling CommonShares other than those pursuant to applicable securities laws and stock exchange policies. There are no restrictions onsales of Common Shares by any of the existing shareholders of the Company following Closing, some of whom maywish to reduce their share position in the Company and sell some or all of their shares. The sale of a substantial numberof the Common Shares in the public market after the Offering, or the perception that such sales may occur, couldadversely affect the prevailing market price of the Common Shares and negatively impact the Company’s ability toraise equity capital in the future.

Risks Relating to the Deep Basin West Acquisition

The Company has completed the Deep Basin West Acquisition to strengthen the position of the Company in theAlberta Deep Basin and to create the opportunity to realize certain other benefits, including anticipated growth anddevelopment opportunities from the Acquired Assets. Achieving the benefits of the Deep Basin West Acquisitiondepends in part on successfully integrating operations in a timely and efficient manner. This will require the dedicationof management effort, time and resources, which may divert management’s focus and resources from other strategicopportunities of the Company and from operational matters during this process.

In connection with the Deep Basin West Acquisition, there may be liabilities that the Company failed to discoveror was unable to quantify in its due diligence, and the Company may not be indemnified for some or all of theseliabilities.

There can be no assurances that the Deep Basin West Acquisition will perform as expected or that the returnsfrom the Deep Basin West Acquisition will support the indebtedness incurred to complete it or the capital expendituresneeded to develop the Acquired Assets.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

There are no legal proceedings Tourmaline is or was a party to, or that any of its property is or was the subject of,since the beginning of Tourmaline’s most recently completed financial year, nor are any such legal proceedings knownto Tourmaline to be contemplated, that involve a claim for damages, exclusive of interest and costs, exceeding 10% ofthe current assets of Tourmaline.

There are no: (a) penalties or sanctions imposed against Tourmaline by a court relating to securities legislation orby a securities regulatory authority since Tourmaline’s incorporation in 2008; (b) other penalties or sanctions imposedby a court or regulatory body against Tourmaline necessary for the prospectus to contain full, true and plain disclosureof all material facts relating to the Common Shares; or (c) settlement agreements Tourmaline entered into before acourt relating to securities legislation or with a securities regulatory authority since Tourmaline’s incorporation in2008.

INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

There is no material interest, direct or indirect, of any: (a) director or executive officer of Tourmaline; (b) personor company that beneficially owns, or controls or directs, directly or indirectly, more than 10% of any class or series ofTourmaline’s voting securities; and (c) associate or affiliate of any of the persons or companies referred to in (a) or(b) above in any transaction since the Company’s incorporation in 2008 that has materially affected or is reasonablyexpected to materially affect Tourmaline other than that Messrs. Rose and Keenan, directors of Tourmaline, weredirectors and shareholders, and Mr. Keenan was also an officer, of Exshaw at the time of the Exshaw Acquisition.

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EXEMPTIONS FROM CERTAIN DISCLOSURE REQUIREMENTS

The Alberta Securities Commission, as principal regulator on behalf of the securities regulatory authorities in eachof the other provinces of Canada, has granted exemptive relief from the requirement contained in Section 32.2 of Form41-101F1 of NI 41-101 that (i) the prospectus contain three years of audited annual financial statements for certain ofthe Tourmaline Significant Acquisitions and (ii) the prospectus contain “financial statements” (as opposed to the“operating statements” contained in the prospectus) for certain of the Tourmaline Significant Acquisitions. See “Indexto Financial Statements” for the financial statements included in this prospectus. The issuance by the Alberta SecuritiesCommission of a final receipt for this prospectus constitutes evidence of the granting of relief from the foregoingrequirements in all jurisdictions in Canada.

AUDITOR, TRANSFER AGENT AND REGISTRAR

The Company’s auditors are KPMG LLP, Chartered Accountants, Suite 2700, 205 – 5th Avenue S.W., Calgary,Alberta T2P 4B9.

The transfer agent and registrar for the Common Shares is Canadian Stock Transfer Company, Inc. at its principaloffices in Calgary, Alberta and Toronto, Ontario.

MATERIAL CONTRACTS

Except for contracts entered into in the ordinary course of business, the only material contract the Company hasentered into since the beginning of the last financial year, or before the beginning of the last financial year that is stillin effect, or will enter into on or prior to Closing is the Underwriting Agreement referred to under the heading “Plan ofDistribution”.

EXPERTS

Names of Experts

The only persons or companies who are named as having prepared or certified a report, valuation, statement oropinion in this prospectus and whose profession or business gives authority to such report, valuation, statement oropinion, are:

(a) Burnet, Duckworth & Palmer LLP, the Company’s counsel; and Blake, Cassels & Graydon LLP, theUnderwriters’ counsel (together, the “Counsel”);

(b) KPMG LLP, Tourmaline and Exshaw’s independent auditors and Tourmaline’s auditors in respect of theAlberta Deep Basin Acquisition; PricewaterhouseCoopers LLP, Pienza and Altia’s independent auditors andauditors in respect of the Wild River Acquisition; BDO Canada LLP, Vigilant’s independent auditors; andErnst & Young LLP, independent auditors in respect of the Greater Hinton Acquisition; and

(c) GLJ, Tourmaline’s independent reserve evaluators; AJM, Exshaw’s independent reserve evaluators andindependent reserve evaluators in respect of the Greater Hinton Acquisition; and Sproule, Altia’sindependent reserve evaluators (collectively, the “Reserve Evaluators”).

Interests of Experts

To the Company’s knowledge, no registered or beneficial interests, direct or indirect, in any securities or otherproperty of the Company or of one of the Company’s associates or affiliates (i) were held by any of the ReserveEvaluators or by the “designated professionals” (as defined in Form 51-102F2) of the Reserve Evaluators, when theReserve Evaluators prepared their respective reports, valuations, statements or opinions referred to herein as havingbeen prepared by such Reserve Evaluators, (ii) were received by any of the Reserve Evaluators or the designatedprofessionals of the Reserve Evaluators after such Reserve Evaluator prepared the report, valuation, statement oropinion in question, or (iii) is to be received by any of the Reserve Evaluators or the designated professionals of theReserve Evaluators.

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None of the Reserve Evaluators nor any director, officer or employee of any of the Reserve Evaluators is or isexpected to be elected, appointed or employed as a director, officer or employee of the Company or of any associate oraffiliate of the Company.

As at the date hereof, each of the Counsel and such Counsel’s respective designated professionals, as a group,beneficially own, directly or indirectly, less than 1% of the outstanding Common Shares.

KPMG LLP has advised the Company that they are independent within the meaning of the Rules of ProfessionalConduct of the Institute of Chartered Accountants of Alberta.

PURCHASERS’ STATUTORY RIGHTS OF WITHDRAWAL AND RESCISSION

Securities legislation in certain of the provinces of Canada provides purchasers with the right to withdraw from anagreement to purchase securities. This right may be exercised within two business days after receipt or deemed receiptof a prospectus and any amendment. In several of the provinces, the securities legislation further provides a purchaserwith remedies for rescission or, in some jurisdictions, revisions of the price or damages if the prospectus and anyamendment contains a misrepresentation or is not delivered to the purchaser, provided that such remedies forrescission, revisions of the price, or damages are exercised by the purchaser within the time limit prescribed by thesecurities legislation of the purchaser’s province. The purchaser should refer to any applicable provisions of thesecurities legislation of the purchaser’s province for the particulars of these rights or consult with a legal advisor.

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AUDITORS’ CONSENTS

KPMG LLP Consent

We have read the initial public offering prospectus of Tourmaline Oil Corp. (the “Company”) datedNovember 15, 2010 relating to the distribution of common shares of the Company. We have complied with Canadiangenerally accepted standards for an auditor’s involvement with offering documents.

We consent to the use in the above-mentioned prospectus of our report to the directors of the Company on theconsolidated balance sheets of the Company as at December 31, 2009 and 2008 and the consolidated statements ofincome (loss), comprehensive income (loss) and retained earnings (deficit) and cash flow for the year endedDecember 31, 2009 and the period from incorporation on July 21, 2008 to December 31, 2008. Our report is datedMay 6, 2010 (except for note 12 which is as of November 15, 2010).

We consent to the use in the above-mentioned prospectus of our report to the shareholders of Exshaw Oil Corp.(“Exshaw”) on the balance sheets of Exshaw as at December 31, 2008 and 2007 and the statements of income andretained earnings and cash flows for the years then ended. Our report is dated April 23, 2009.

We consent to the use in the above-mentioned prospectus of our report to the directors of Tourmaline on theschedule of Revenues, Royalties and Operating Expenses for the Alberta Deep Basin Properties for the year endedDecember 31, 2008. Our report is dated October 9, 2009.

(signed) “KPMG LLP”Chartered Accountants

Calgary, CanadaNovember 15, 2010

PricewaterhouseCoopers LLP Consent

We have read the initial public offering prospectus of Tourmaline Oil Corp. (the “Company”) datedNovember 15, 2010 relating to the distribution of common shares of the Company. We have complied with Canadiangenerally accepted standards for an auditor’s involvement with offering documents.

We consent to the use in the above-mentioned prospectus of our report to the Shareholders of Pienza PetroleumInc. (“Pienza”) on the balance sheets of Pienza as at December 31, 2008 and 2007 and the statements of operations anddeficit and cash flows for each of the years in the two-year period ended December 31, 2008. Our report is datedMay 4, 2009.

We consent to the use in the above-mentioned prospectus of our report to the Shareholder of Altia Energy Ltd.(“Altia”) on the balance sheets of Altia as at March 31, 2009 and 2008 and the statements of operations and deficit andcash flows for each of the years in the two-year period ended March 31, 2009. Our report is dated June 23, 2009.

We consent to the use in the above-mentioned prospectus of our report to the Directors of EnCana Corporation onthe Schedule of Revenues, Royalties and Operating Expenses for the years ended December 31, 2008 and 2007 for theWild River, Harley, Olsen and Sundance Properties. Our report is dated October 5, 2009.

(signed) “PricewaterhouseCoopers LLP”Chartered Accountants

Calgary, AlbertaNovember 15, 2010

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BDO Canada LLP Consent

We have read the initial public offering prospectus of Tourmaline Oil Corp. (the “Company”) datedNovember 15, 2010 relating to the distribution of common shares of the Company. We have complied with Canadiangenerally accepted standards for an auditors’ involvement with offering documents.

We consent to the use in the above-mentioned prospectus of our report to the shareholders of Vigilant ExplorationInc. (“Vigilant”) on the consolidated balance sheets of Vigilant as at June 30, 2009 and 2008 and the consolidatedstatements of operations and deficit and cash flows for each of the years in the two-year period ended June 30, 2009.Our report is dated October 30, 2009.

(signed) “BDO Canada LLP”Chartered Accountants


Ernst & Young LLP Consent

We have read the initial public offering prospectus of Tourmaline Oil Corp. (the “Company”) datedNovember 15, 2010 relating to the distribution of common shares of the Company. We have complied with Canadiangenerally accepted standards for an auditors’ involvement with offering documents.

We consent to the use in the above-mentioned prospectus of our report to the Board of Directors of TalismanEnergy Inc. on the Schedule of Revenue, Royalties and Operating Expenses of the Greater Hinton Properties, asdescribed in Note 1 to the Schedule, for the years ended December 31, 2009 and 2008. Our report is dated July 23,2010.

(signed) “Ernst & Young LLP”Chartered Accountants


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GLOSSARY OF SELECTED GENERAL TERMS

In this prospectus, including in Appendix “A” and “B” attached hereto, unless otherwise indicated or the contextotherwise requires, the following terms have the meaning set forth below:

“ABCA” means the Business Corporations Act (Alberta).

“AJM” means AJM Petroleum Consultants, an independent qualified reserve evaluator.

“AJM Exshaw Reserve Report” means the report of AJM dated effective as of December 31, 2009, with apreparation date of March 19, 2010, evaluating certain crude oil and natural gas assets of Exshaw.

“AJM Greater Hinton Reserve Report” means the report of AJM dated effective as of November 30, 2009, witha preparation date of December 28, 2009, evaluating certain crude oil and natural gas assets acquired by Tourmalinepursuant to the Greater Hinton Acquisition.

“Alberta Deep Basin” means one of the Company’s current core areas located within the Deep Basinapproximately 250 kilometres west of Edmonton, Alberta, as more particularly described under “Description of CoreLong-Term Growth Areas – Alberta Deep Basin Core Area”.

“Alberta Deep Basin Acquisition” means the acquisition by Tourmaline on April 30, 2009 of certain crude oiland natural gas assets in the Alberta Deep Basin.

“Altia” means Altia Energy Ltd., a wholly-owned subsidiary of the Company.

“Altia Acquisition” means the acquisition by Tourmaline on January 14, 2010 of all of the outstanding shares ofAltia, a private oil and gas company.

“Audit Committee” means the audit committee of the Board.

“Berkley” means Berkley Petroleum Corp., an oil and gas company previously founded and managed by certainkey members of Tourmaline’s senior management team.

“Board” or “Board of Directors” means the board of directors of the Company.

“Canadian GAAP” or “GAAP” means Canadian generally accepted accounting principles.

“CEO” has the meaning ascribed thereto under the heading “Executive Compensation”.

“CFO” has the meaning ascribed thereto under the heading “Executive Compensation”.

“Closing” means the closing of the Offering.

“Closing Date” means the date of closing of the Offering.

“Common Shares” means the common shares in the capital of the Company as constituted on the date hereof.

“Concurrent Private Placement” means the private placement by the Company to the Private Placees,concurrent with the closing of the Offering, of an aggregate of 850,000 Private Placement Shares at the Offering Pricefor gross proceeds to the Company of $17.85 million.

“Credit Facilities” means, collectively, the Tourmaline Credit Facility and the Exshaw Credit Facility.

“Deep Basin” means that area of the WCSB covering an area of over 19,000 square miles from Central Albertaalong the foothills of the Rocky Mountains to NEBC where much of the Mesozoic section of clastic rocks are gas-saturated downdip of the regional water line.

“Deep Basin West Acquisition” means the acquisition by Tourmaline of certain crude oil and natural gas assetsin the Alberta Deep Basin, as described under “Recent Developments – Deep Basin West Acquisition”.

“Duvernay” means Duvernay Oil Corp., an oil and gas company previously founded and managed by certain keymembers of Tourmaline’s senior management team.

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“Escrow Agreement” has the meaning ascribed thereto under “Escrowed Common Shares”.

“Exshaw” means Exshaw Oil Corp., a 90.6% owned subsidiary of the Company.

“Exshaw Acquisition” means the acquisition by Tourmaline on November 10, 2009 of approximately 90.6% ofthe outstanding shares of Exshaw, a private oil and gas company.

“Exshaw Credit Facility” has the meaning ascribed thereto under the heading “Consolidated Capitalization”.

“Exshaw Operating Facility” has the meaning ascribed thereto under the heading “Consolidated Capitalization”.

“Exshaw Revolving Facility” has the meaning ascribed thereto under the heading “Consolidated Capitalization”.

“Flow-Through Shares” means Common Shares issued on a “flow-through” basis pursuant to the Tax Act.

“Form 41-101F1” means Form 41-101F1 – Information Required in a Prospectus.

“G&A” means general and administrative.

“GLJ” means GLJ Petroleum Consultants Ltd., an independent qualified reserve evaluator.

“GLJ Tourmaline Reserve Report” means the report of GLJ dated effective as of December 31, 2009, with apreparation date of April 9, 2010, evaluating the oil and gas properties of Tourmaline.

“Greater Hinton Acquisition” means the acquisition by Tourmaline on June 1, 2010 of certain crude oil andnatural gas assets in the Alberta Deep Basin.

“Greater Peace River High” means one of the Company’s current core areas extending from Grande Prairie,Alberta to approximately 30 kilometres southwest of Fort St. John, NEBC, as more particularly described under“Description of Core Long-Term Growth Areas – Greater Peace River High Core Area”.

“IFRS” means International Financial Reporting Standards.

“Lead Underwriter” means Peters & Co. Limited.

“Named Executive Officers” or “NEOs” has the meaning ascribed thereto under the heading “ExecutiveCompensation”.

“NEB” means the National Energy Board (Canada).

“NEBC” means north east British Columbia.

“NI 41-101” means National Instrument 41-101 – General Prospectus Requirements.

“NI 51-101” means National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities.

“NI 51-102” means National Instrument 51-102 – Continuous Disclosure Obligations.

“NI 52-109” means National Instrument 52-109 – Certification of Disclosure in Issuers’ Annual and InterimFilings.

“NI 52-110” means National Instrument 52-110 – Audit Committees.

“NI 58-101” means National Instrument 58-101 – Disclosure of Corporate Governance Practices.

“NP 58-201” means National Policy 58-201 – Corporate Governance Guidelines.

“Offering” means the offering of Common Shares described in this prospectus (not including the issuance of anyCommon Shares pursuant to the exercise of the Over-Allotment Option).

“Option” means an option to purchase a Common Share granted under the Option Plan.

“Option Plan” means the share option plan of the Company.

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“Over-Allotment Option” means the option granted by the Company to the Underwriters to purchase from theCompany, at the Offering price up to an additional 1,500,000 Common Shares, all as more particularly describedherein under the heading “Plan of Distribution”.

“Pienza” means Pienza Petroleum Inc.

“Pienza Acquisition” means the acquisition by Tourmaline on September 15, 2009 of Pienza, a private oil andgas company.

“Private Placees” means, together, the Company’s President and Chief Executive Officer, Mr. Michael L. Rose,and Executive Vice President, Exploration, Mr. Robert N. Yurkovich

“Private Placement Shares” means the 850,000 Common Shares to be issued by the Company to the PrivatePlacees pursuant to the Concurrent Private Placement.

“Reserve Reports” means, together, the GLJ Tourmaline Reserve Report and the AJM Exshaw Reserve Report.

“Sproule” means Sproule Associates Limited, an independent qualified reserve evaluator.

“Sproule Altia Reserve Report” means the report of Sproule dated effective as of March 31, 2009, with apreparation date of April 21, 2009, evaluating certain oil and gas assets of Altia.

“Tax Act” means the Income Tax Act (Canada) and the regulations promulgated thereunder.

“Tourmaline” or the “Company” means Tourmaline Oil Corp., a corporation incorporated under the ABCA.

“Tourmaline Credit Facility” has the meaning ascribed thereto under the heading “Consolidated Capitalization”.

“Tourmaline Operating Facility” has the meaning ascribed thereto under the heading “ConsolidatedCapitalization”.

“Tourmaline Revolving Facility” has the meaning ascribed thereto under the heading “ConsolidatedCapitalization”.

“Tourmaline Significant Acquisitions” means, collectively, the Alberta Deep Basin Acquisition, Wild RiverAcquisition, Pienza Acquisition, Vigilant Acquisition, Exshaw Acquisition, Altia Acquisition and Greater HintonAcquisition.

“TSX” means the Toronto Stock Exchange.

“U.S.” or “United States” means the United States of America, its territories and possessions, any state of theUnited States and the District of Columbia.

“U.S. Securities Act” means the United States Securities Act of 1933, as amended.

“Underwriters” means, collectively, Peters & Co. Limited, FirstEnergy Capital Corp., Scotia Capital Inc., TDSecurities Inc. and Cormark Securities Inc.

“Underwriting Agreement” means the underwriting agreement dated November 15, 2010 among the Companyand the Underwriters.

“Vigilant” means Vigilant Exploration Inc.

“Vigilant Acquisition” means the acquisition by Tourmaline on November 10, 2009 of Vigilant, a private oil andgas company.

“WCSB” means the Western Canadian Sedimentary Basin.

“Wild River Acquisition” means the acquisition by Tourmaline on August 28, 2009 of certain crude oil andnatural gas assets in the Alberta Deep Basin.

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GLOSSARY OF SELECTED OIL AND GAS TERMS

In this prospectus, unless otherwise indicated or the context otherwise requires, the following terms have themeaning set forth below:

“2D seismic data” means two-dimensional seismic data, being an interpretive data that allows a view of a verticalcross-section beneath a prospective area.

“3D seismic data” means three-dimensional seismic data, being geophysical data that depicts the subsurfacestrata in three dimensions. 3D seismic data typically provides a more detailed and accurate interpretation of thesubsurface strata than 2D seismic data.

“AECO” means the natural gas storage facility located at Suffield, Alberta.

“API gravity” means the American Petroleum Institute gravity, which is a measure of how heavy or light apetroleum liquid is compared to water. If a petroleum liquid’s API gravity is greater than 10, it is lighter and floats onwater; if less than 10, it is heavier than water and sinks. API gravity is thus a measure of the relative density of apetroleum liquid and the density of water, but it is used to compare the relative densities of petroleum liquids.

“API” means the American Petroleum Institute.

“basin” means a large natural depression on the earth’s surface in which sediments generally brought by wateraccumulate.

“COGE Handbook” means the Canadian Oil and Gas Evaluation Handbook prepared jointly by The Society ofPetroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum(Petroleum Society), as amended from time to time.

“completion” means the process of treating a drilled well followed by the installation of permanent equipment forthe production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriateagency.

“delineation well” means a well that is so located in relation to another well penetrating an accumulation ofpetroleum that there is a reasonable expectation that another portion of the accumulation will be penetrated by the firstmentioned well and that the drilling of the first-mentioned well is necessary in order to determine the commercial valueof the accumulation.

“deliverability” means the amount of natural gas a well or field can supply in a give period of time.

“developed non-producing reserves” are those reserves that either have not been on production, or havepreviously been on production, but are shut in, and the date of resumption of production is unknown.

“developed producing reserves” are those reserves that are expected to be recovered from completion intervalsopen at the time of the estimate. These reserves may be currently producing or, if shut in, they must have previouslybeen on production, and the date of resumption of production must be known with reasonable certainty.

“developed reserves” are those reserves that are expected to be recovered from existing wells and installedfacilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared tothe cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producingand non-producing.

“development costs” means costs incurred to obtain access to reserves and to provide facilities for extracting,treating, gathering and storing the oil and gas from the reserves. More specifically, development costs, includingapplicable operating costs of support equipment and facilities and other costs of development activities, are costsincurred to:

(a) gain access to and prepare well locations for drilling, including surveying well locations for the purpose ofdetermining specific development drilling sites, clearing ground, draining, road building, and relocatingpublic roads, gas lines and power lines, to the extent necessary in developing the reserves;

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(b) drill and equip development wells, development type stratigraphic test wells and service wells, including thecosts of platforms and of well equipment such as casing, tubing, pumping equipment and the wellheadassembly;

(c) acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds,measuring devices and production storage tanks, natural gas cycling and processing plants, and central utilityand waste disposal systems; and

(d) provide improved recovery systems.

“development well” means a well drilled inside the established limits of an oil or gas reservoir or in closeproximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive.

“dry hole” means a well found to be incapable of producing hydrocarbons in sufficient quantities such thatproceeds from the sale of such production exceed production expenses and taxes.

“exploration costs” means costs incurred in identifying areas that may warrant examination and in examiningspecific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drillingexploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiringthe related property and after acquiring the property. Exploration costs, which include applicable operating costs ofsupport equipment and facilities and other costs of exploration activities, are:

(a) costs of topographical, geochemical, geological and geophysical studies, rights of access to properties toconduct those studies, and salaries and other expenses of geologists, geophysical crews and othersconducting those studies;

(b) costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income andcapital taxes) on properties, legal costs for title defence, and the maintenance of land and lease records;

(c) dry hole contributions and bottom hole contributions;

(d) costs of drilling and equipping exploratory wells; and

(e) costs of drilling exploratory type stratigraphic test wells.

“exploration well” means a well that is not a development well, a service well or a stratigraphic test well.

“field” means an area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the sameindividual geological structural feature or stratigraphic condition. The field name refers to the surface area, although itmay refer to both the surface and the underground productive formations.

“forecast prices and costs” are those:

(a) generally acceptable as being a reasonable outlook of the future; and

(b) if and only to the extent that, there are fixed or presently determinable future prices or costs to whichTourmaline is legally bound by a contractual or other obligation to supply a physical product, including thosefor an extension period of a contract that is likely to be extended, those prices or costs rather than the pricesand costs referred to in paragraph (a).

“formation” means a layer of rock which has distinct characteristics that differ from nearby rock.

“frac” or “fracture” refers to the hydraulic fracturing of a hydrocarbon bearing zone in order to enhanceproduction.

“future income taxes” when used are estimated:

(a) making appropriate allocations of estimated unclaimed costs and losses carried forward for tax purposes,between oil and gas activities and other business activities;

(b) without deducting estimated future costs that are not deductible in computing taxable income;

(c) taking into account estimated tax credits and allowances; and

(d) applying to the future pre-tax net cash flows relating to Tourmaline’s oil and gas activities the appropriateyear-end statutory tax rates, taking into account future tax rates already legislated.

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“GHG” means greenhouse gas.

“horizontal drilling” means a drilling technique used in certain formations where a well is drilled vertically to acertain depth and then drilled at a right angle within a specified interval.

“infill wells” means wells drilled into the same pool as known producing wells so that oil or natural gas does nothave to travel as far through the formation.

“multi-stage fracture stimulation” refers to the use of multiple stimulations to increase productivity of a wellthat result in the formation of fractures in the wellbore; the technology involves segregating sections of the well withpackers or other mechanical methods, and then pumping a high-pressure fracture treatment and utilizing a series ofdownhole valves to create a number of fractures along the length of the wellbore.

“net acres” means the percentage of total acres an owner has out of a particular number of acres, or a specifiedtract. An owner who has 50% interest in 100 acres owns 50 net acres.

“probable reserves” are those additional reserves that are less certain to be recovered than proved reserves. It isequally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated provedplus probable reserves.

“proved reserves” are those reserves that can be estimated with a high degree of certainty to be recoverable. It islikely that the actual remaining quantities recovered will exceed the estimated proved reserves.

“recompletion” means the process of re-entering an existing wellbore that is either producing or not producingand completing new reservoirs in an attempt to establish or increase existing production.

“reserves” are estimated remaining quantities of oil and natural gas and related substances anticipated to berecoverable from known accumulations, as of a given date, based on: (i) analysis of drilling, geological, geophysicaland engineering data; (ii) the use of established technology; and (iii) specified economic conditions, which aregenerally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with theestimates.

“reservoir” means a porous and permeable underground formation containing a natural accumulation ofproducible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from otherreservoirs.

“resource play” refers to drilling programs targeted at regionally distributed oil or natural gas accumulations;successful exploitation of these reservoirs is dependent upon technologies such as horizontal drilling and multi-stagefracture stimulation to access large rock volumes in order to produce economic quantities of oil or natural gas.

“service well” means a well drilled or completed for the purpose of supporting production in an existing field.Wells in this class are drilled for the following specific purposes: gas injection (natural gas, propane, butane or fluegas), water injection, steam injection, air injection, salt water disposal, water supply for injection, observation orinjection for combustion.

“spacing” means the distance between wells producing from the same reservoir. Spacing is often expressed interms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“tight gas” or “tight natural gas” refers to natural gas found in sedimentary layers of tightly packed rock.

“undeveloped reserves” are those reserves expected to be recovered from known accumulations where a significantexpenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production.They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.

“wellbore” means the hole drilled by the bit that is equipped for oil or gas production on a completed well. Alsocalled well or borehole.

“working interest” means the right granted to the lessee of a property to explore for and to produce and own oil,gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either acash, penalty, or carried basis.

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CERTAIN RESERVES DATA INFORMATION

The determination of oil and gas reserves involves the preparation of estimates that have an inherent degree ofassociated uncertainty. Categories of proved, probable and possible reserves have been established to reflect the levelof these uncertainties and to provide an indication of the probability of recovery.

The estimation and classification of reserves requires the application of professional judgment combined withgeological and engineering knowledge to assess whether or not specific reserves classification criteria have beensatisfied. Knowledge of concepts including uncertainty and risk, probability and statistics, and deterministic andprobabilistic estimation methods is required to properly use and apply reserves definitions.

The qualitative certainty levels referred to in the definitions set forth in the “Glossary of Selected Oil and GasTerms” above are applicable to individual reserve entities (which refers to the lowest level at which reservescalculations are performed) and to reported reserves (which refers to the highest level sum of individual entityestimates for which reserves are presented). Reported reserves should target the following levels of certainty under aspecific set of economic conditions:

(a) at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimatedproved reserves; and

(b) at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of theestimated proved plus probable reserves.

A qualitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories isdesirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reservesestimates will be prepared using deterministic methods that do not provide a mathematically derived quantitativemeasure of probability. In principle, there should be no difference between estimates prepared using probabilistic ordeterministic methods.

Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation isprovided in the COGE Handbook.

In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undevelopedcategories or to sub-divide the developed reserves for the pool between developed producing and developednonproducing. This allocation should be based on the estimator’s assessment as to the reserves that will be recoveredfrom specific wells, facilities and completion intervals in the pool and their respective development and productionstatus.

In this prospectus:

(a) the discounted and undiscounted net present value of future net revenues attributable to reserves do notrepresent the fair market value of reserves;

(b) there is no assurance that the forecast prices and costs assumptions will be attained and variances could bematerial. The recovery and reserve estimates of crude oil, NGL and natural gas reserves provided in thisprospectus are estimates only and there is no guarantee that the estimated reserves will be recovered. Actualcrude oil, natural gas and NGL reserves may be greater than or less than the estimates provided in thisprospectus;

(c) the estimates of reserves and future net revenue for individual properties may not reflect the same confidencelevel as estimates of reserves and future net revenue for all properties, due to the effects of aggregation; and

(d) Boes may be misleading, particularly if used in isolation. A Boe conversion ratio of 6 Mcf : 1 Bbl is based onan energy equivalency conversion method primarily applicable at the burner tip and does not represent avalue equivalency at the wellhead.

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SELECTED ABBREVIATIONS

In this prospectus, unless otherwise indicated or the context otherwise requires, the following abbreviations shallhave the meaning set forth below:

Crude Oil and Natural Gas LiquidsBbls/d barrels of oil per dayBbls or Bbl barrels of oilBoe barrel of oil equivalentBoe/d barrel of oil equivalent per day$/Bbl Canadian dollars per barrel of oil$/Boe Canadian dollars per barrel of oil equivalentMbbls thousand barrelsMBoe thousand barrels of oil equivalentMbbls/d thousand barrels of oil per dayMMbbls million barrels of oilMMboe million barrels of oil equivalentMMboe/d million barrels of oil equivalent per dayNGL natural gas liquids

Natural GasBcf billion cubic feetcf cubic feetMcf thousand cubic feetMcf/d thousand cubic feet per dayMcfe thousand cubic feet of gas equivalentMcfe/d thousand cubic feet of gas equivalent per dayMMbtu million British thermal unitsMMcf million cubic feetMMcf/d million cubic feet per dayMMcfe million cubic feet of gas equivalentMMcfe/d million cubic feet of gas equivalent per day$/Mcf Canadian dollars per thousand cubic feet$/MMbtu Canadian dollars per million British thermal

unitsGJ gigajouleGJs/d gigajoules per day$/GJ Canadian dollar per gigajoule

Otherkm kilometreskm2 square kilometres$, $Cdn, Cdn$ or Canadian dollars$dollars$000s or M$ thousand dollarsMM$ million dollars$US or US$ United States dollars2D two dimensional3D three dimensional

SELECTED CONVERSIONS

The following table sets forth certain standard conversions from Standard Imperial Units to the InternationalSystem of Units (or metric units).

To Convert From To Multiply By

Mcf . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . cubic metres 28.320cubic metres . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . cubic feet 35.315Bbls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . cubic metres 0.159cubic metres . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bbls 6.290feet . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . metres 0.305metres . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . feet 3.281miles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . kilometres 1.609kilometres . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . miles 0.621acres . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . hectares 0.405hectares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . acres 2.471

123

EXCHANGE RATE DATA

The following table sets forth, for the periods indicated, the high, low, average and period-end noon spot rates ofexchange for the Canadian dollar, expressed in U.S. dollars per Canadian dollar, based on data published by the Bankof Canada.

Nine Months Ended September 30, 2010 Year Ended December 31,

2010 2009 2009 2008 2007

US$ US$ US$ US$ US$

Highest rate during the period . . . . . . . . . . . . . . . . . . . . 1.0052 0.9442 0.9716 1.0289 1.0905Lowest rate during the period . . . . . . . . . . . . . . . . . . . . 0.9218 0.7653 0.7692 0.7711 0.8437Average noon spot rate for the period(1) . . . . . . . . . . . . 0.9654 0.8547 0.8833 0.9397 0.9418Rate at the end of the period . . . . . . . . . . . . . . . . . . . . . 0.9711 0.9327 0.9555 0.8166 1.0120

Note:(1) Determined by averaging the rates on the last business day of each month during the respective period.

On November 15, 2010, the noon rate of exchange posted by the Bank of Canada for conversion of Canadiandollars into U.S. dollars was Cdn$1.00 equals US$0.9935.

FORWARD-LOOKING STATEMENTS

Certain statements contained in this prospectus constitute forward-looking statements. These statements relate tofuture events or the Company’s future performance. All statements other than statements of historical fact are forward-looking statements. The use of any of the words “anticipate”, “plan”, “contemplate”, “continue”, “estimate”, “expect”,“intend”, “propose”, “might”, “may”, “will”, “shall”, “project”, “should”, “could”, “would”, “believe”, “predict”,“forecast”, “pursue”, “potential” and “capable” and similar expressions are intended to identify forward-lookingstatements. These statements involve known and unknown risks, uncertainties and other factors that may cause actualresults or events to differ materially from those anticipated in such forward-looking statements. No assurance can begiven that these expectations will prove to be correct and such forward-looking statements included in this prospectusshould not be unduly relied upon. These statements speak only as of the date of this prospectus. In addition, thisprospectus may contain forward-looking statements and forward-looking information attributed to third-party industrysources.

In particular, this prospectus contains forward-looking statements pertaining to the following:

Š the reserve potential of the Company’s assets;

Š the production from the Company’s assets;

Š the Company’s growth strategy and opportunities;

Š the Company’s capital exploration and development programs and future capital requirements;

Š the estimated quantity and value of the Company’s proved and probable reserves;

Š the Company’s estimates of future interest and foreign exchange rates;

Š the Company’s environmental considerations;

Š the Company’s expectations regarding commodity prices;

Š the Company’s expectation regarding reduction in its operating costs in 2010 and 2011;

Š the timing of commencement of certain of the Company’s operations and the level of production anticipatedby the Company;

Š the potential for production disruption and constraints;

Š supply and demand fundamentals for crude oil and natural gas;

Š the Company’s access to adequate pipeline capacity;

Š the Company’s access to third-party infrastructure;

124

Š the Company’s drilling and recompletion plans;

Š the Company’s 2011 expected capital expenditures for the remainder of 2010 and for 2011;

Š industry conditions pertaining to the oil and gas industry;

Š the Company’s plans for, and results of, exploration and development activities;

Š the planned construction of the Company’s gathering, transportation and processing facilities and relatedinfrastructure;

Š the use of the proceeds of the Offering and the Concurrent Private Placement;

Š the timing for receipt of regulatory approvals;

Š the Company’s treatment under governmental regulatory regimes and tax laws;

Š the Company’s future G&A and DD&A expenses;

Š the Company’s expectations regarding having adequate human resource staffing;

Š the compensation that is expected to be paid to the executive officers and directors of the Company in 2010and thereafter; and

Š the Company’s dividend policy.

With respect to forward-looking statements and forward-looking information contained in this prospectus,assumptions have been made regarding, among other things:

Š future crude oil and natural gas prices;

Š the Company’s ability to obtain qualified staff and equipment in a timely and cost–efficient manner;

Š the regulatory framework governing royalties, taxes and environmental matters in the jurisdictions in whichthe Company conducts its business and any other jurisdictions in which the Company may conduct itsbusiness in the future;

Š the Company’s ability to market production of oil and natural gas successfully to customers;

Š the Company’s future production levels;

Š the applicability of technologies for recovery and production of the Company’s reserves;

Š the recoverability of the Company’s reserves;

Š future capital expenditures to be made by the Company;

Š future cash flows from production meeting the expectations stated in this prospectus;

Š future sources of funding for the Company’s capital program;

Š the Company’s future debt levels;

Š geological and engineering estimates in respect of the Company’s reserves;

Š the geography of the areas in which the Company is conducting exploration and development activities;

Š the intentions of the Board with respect to the executive compensation plans and corporate governanceprograms described herein;

Š the impact of competition on the Company; and

Š the Company’s ability to obtain financing on acceptable terms.

Actual results could differ materially from those anticipated in these forward-looking statements as a result of therisk factors set forth below and included elsewhere in this prospectus, including:

Š operating and capital costs;

Š the Company’s status and stage of development;

Š general economic, market and business conditions;

125

Š volatility in market prices for crude oil and natural gas and hedging activities related thereto;

Š risks related to the exploration, development and production of oil and natural reserves;

Š risks related to the timing of completion of the Company’s projects;

Š competition for, among other things, capital, the acquisition of reserves and resources and skilled personnel;

Š operational hazards;

Š actions by governmental authorities, including changes in government regulation and taxation;

Š environmental risks and hazards;

Š risks inherent in the exploration, development and production of oil and natural gas which may createliabilities to the Company in excess of the Company’s insurance coverage;

Š failure to accurately estimate abandonment and reclamation costs;

Š failure of third parties’ reviews, reports and projections to be accurate;

Š the availability of capital on acceptable terms;

Š political risks;

Š changes to royalty or tax regimes;

Š the failure of the Company or the holders of certain licenses or leases to meet specific requirements of suchlicenses or leases;

Š claims made in respect of the Company’s properties or assets;

Š aboriginal claims;

Š unforeseen title defects;

Š risks arising from future acquisition activities;

Š hedging strategies;

Š potential conflicts of interest;

Š the potential impact of the implementation of IFRS on the Company’s financial results;

Š the potential for management estimates and assumptions to be inaccurate;

Š risks associated with establishing and maintaining systems of internal controls;

Š risks related to the reliance on historical financial information, including that historical financial informationdoes not reflect the added costs that the Company expects to incur as a public entity;

Š restrictions contained in the Credit Facilities;

Š additional indebtedness;

Š volatility in the market price of the Common Shares;

Š the absence of an existing public market for the Common Shares;

Š the effect that the issuance of additional securities by the Company could have on the market price of theCommon Shares;

Š failure to engage or retain key personnel;

Š potential losses which would stem from any disruptions in production, including work stoppages or otherlabour difficulties, or disruptions in the transportation network on which the Company is reliant;

Š uncertainties inherent in estimating quantities of oil and natural gas reserves;

Š failure to acquire or develop replacement reserves;

126

Š geological, technical, drilling and processing problems, including the availability of equipment and access toproperties;

Š failure by counterparties to make payments or perform their operational or other obligations to the Companyin compliance with the terms of contractual arrangements between the Company and such counterparties;

Š current global financial conditions, including fluctuations in interest rates, foreign exchange rates and stockmarket volatility;

Š discretion in the use of proceeds of the Offering; and

Š the other factors discussed under “Risk Factors” in this prospectus.

In addition, information and statements in this prospectus relating to “reserves” are deemed to be forward-lookinginformation and statements, as they involve the implied assessment, based on certain estimates and assumptions, thatthe reserves described exist in the quantities predicted or estimated, and that the reserves described can be profitablyproduced in the future. See also “Certain Reserves Data Information”. Readers are cautioned that the foregoing list ofrisk factors should not be construed as exhaustive.

The forward-looking statements included in this prospectus are expressly qualified by this cautionarystatement and are made as of the date of this prospectus. The Company does not undertake any obligation topublicly update or revise any forward-looking statements except as required by applicable securities laws.

GAAP AND NON-GAAP FINANCIAL MEASURES

The Company’s financial statements included in this prospectus have been prepared in accordance with CanadianGAAP, as applied to its financial statements.

This prospectus makes reference to the terms “funds from operations”, “net debt”, “operating netback” and“working capital (adjusted for the fair value of financial instruments and future taxes)”, which are not recognizedmeasures under Canadian GAAP and do not have a standardized meaning prescribed by Canadian GAAP.Accordingly, the Company’s use of these terms may not be comparable to similarly defined measures presented byother companies. Tourmaline defines funds from operations as cash provided by operations before changes in non-cashworking capital, defines operating netback as revenue less royalties, transportation costs and operating expenses anddefines working capital (adjusted for the fair value of financial instruments and future taxes) as working capitalexcluding the fair value of financial instruments and future taxes. Net debt is defined as long-term bank debt plusworking capital (adjusted for the fair value of financial instruments and future taxes). Management uses thesenon-GAAP measurements for its own performance measures and to provide its shareholders and potential investorswith a measurement of the Company’s efficiency and its ability to generate the cash necessary to fund a portion of itsfuture growth expenditures or to repay debt. Investors are cautioned, however, that these measures should not beconstrued as an alternative to net income determined in accordance with GAAP as an indication of Tourmaline’sperformance. The reconciliation of funds from operations to cash flow from operating activities and the calculation ofoperating netback is set out under the heading “Management’s Discussion and Analysis – Non-GAAP FinancialMeasures”.

127

INDEX TO FINANCIAL STATEMENTSPage

Tourmaline Financial StatementsHistorical Financial Statements

Unaudited interim consolidated balance sheets as at September 30, 2010 and consolidated statements ofincome (loss), comprehensive income (loss) and retained earnings (deficit) and cash flow for the threeand nine months ended September 30, 2010 and 2009 of Tourmaline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FS-2

Audited consolidated balance sheets of Tourmaline as at December 31, 2009 and 2008 and consolidatedstatements of income (loss), comprehensive income (loss) and retained earnings (deficit) and cash flowfor the year ended December 31, 2009 and the period from incorporation on July 21, 2008 toDecember 31, 2008, together with the auditors’ report thereon . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FS-16

Pro Forma Financial StatementsUnaudited pro forma consolidated balance sheet of Tourmaline as at September 30, 2010 and unaudited

pro forma consolidated statements of income (loss) for the nine months ended September 30, 2010 andthe year ended December 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FS-34

Business Acquisition Financial StatementsAlberta Deep Basin Acquisition

Unaudited schedule of revenues, royalties and operating expenses for the three months ended March 31,2009 and 2008 and for the year ended December 31, 2007 and audited schedule of revenues, royaltiesand operating expenses for the year ended December 31, 2008 for the Alberta Deep Basin Properties,together with the auditors’ report thereon . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FS-42

Wild River AcquisitionUnaudited schedule of revenues, royalties and operating expenses for the six months ended June 30, 2009

and 2008 and audited schedule of revenues, royalties and operating expenses for the years endedDecember 31, 2008 and 2007 for the Wild River, Harley, Olsen and Sundance Properties, together withthe auditors’ report thereon . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FS-45

Pienza AcquisitionUnaudited balance sheets of Pienza as at June 30, 2009 and statements of operations and deficit and cash

flows for the three and six months ended June 30, 2009 and 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FS-47Audited consolidated balance sheets of Pienza as at December 31, 2008 and 2007 and statement of

operations and deficit and cash flows for the years ended December 31, 2008 and 2007, together withthe auditors’ report thereon . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FS-56

Vigilant AcquisitionUnaudited consolidated balance sheets of Vigilant as at September 30, 2009 and June 30, 2009 and

consolidated statements of operations and deficit and cash flows for the three months endedSeptember 30, 2009 and 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FS-66

Audited consolidated balance sheets of Vigilant as at June 30, 2009 and 2008 and consolidated statementsof operations and deficit and cash flows for the years ended June 30, 2009 and 2008, together with theauditors’ report thereon . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FS-80

Exshaw AcquisitionUnaudited balance sheet of Exshaw as at September 30, 2009 and statements of income and retained

earnings and cash flow for the three and nine months ended September 30, 2009 and 2008 . . . . . . . . . . . FS-99Audited balance sheets of Exshaw as at December 31, 2008 and 2007 and statements of income and

retained earnings and cash flows for the years ended December 31, 2008 and 2007, together with theauditors’ report thereon . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FS-110

Altia AcquisitionUnaudited interim balance sheets of Altia as at December 31, 2009 and statements of operations and deficit

and cash flows for the three and nine months ended December 31, 2009 and 2008 . . . . . . . . . . . . . . . . . . . . FS-124Audited balance sheets of Altia as at March 31, 2009 and 2008 and statement of operations and deficit and

cash flows for the years ended March 31, 2009 and 2008, together with the auditors’ report thereon . . . . . . FS-137Greater Hinton Acquisition

Unaudited schedule of revenue, royalties and operating expenses of the Greater Hinton Properties for thethree months ended March 31, 2010 and 2009 and audited schedule of revenue, royalties and operatingexpenses of the Greater Hinton Properties for the years ended December 31, 2009 and 2008, togetherwith the auditors’ report thereon . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FS-151

FS-1


CONSOLIDATED FINANCIAL STATEMENTS

INTERIM CONSOLIDATED BALANCE SHEETS

(Unaudited)

(000s) September 30, 2010 December 31, 2009

AssetsCurrent assets:

Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ 199,789Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52,988 45,129Prepaid expenses and deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,797 3,210Fair value of financial instruments (note 9) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16,633 324

72,418 248,452Investment (note 3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,745 632Fair value of financial instruments (note 9) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,255 —Property, plant and equipment (note 2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,458,818 754,798

$1,540,236 $1,003,882

Liabilities and Shareholders’ EquityCurrent liabilities:

Accounts payable and accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 134,099 $ 86,938Future taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,473 —

137,572 86,938Asset retirement obligations (note 4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12,189 7,208Bank debt (note 5) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41,186 —Long-term obligation (note 6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,520 —Future taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28,930 780Non-controlling interest (note 7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13,680 13,526Shareholders’ equity:

Share capital (note 8) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,270,156 895,095Contributed surplus (note 8) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,541 2,018Retained earnings (deficit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,462 (1,683)

1,291,159 895,430

$1,540,236 $1,003,882

Commitments (note 10)Subsequent events (notes 9 and 11)

See accompanying notes to the consolidated financial statements.

FS-2


INTERIM CONSOLIDATED STATEMENTS OF INCOME (LOSS),COMPREHENSIVE INCOME (LOSS) AND RETAINED EARNINGS (DEFICIT)

(Unaudited) Three Months Ended Nine Months Ended

(000s)September 30,

2010September 30,

2009September 30,

2010September 30,

2009

Revenue:Oil and natural gas sales . . . . . . . . . . . . . . . . . . . . . . . . . . $46,144 $ 7,611 $134,304 $13,197Realized gain on financial instruments . . . . . . . . . . . . . . . 5,699 — 10,882 —Unrealized gain (loss) on financial instruments

(note 9) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,818 — 21,637 —

58,661 7,611 166,823 13,197Royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,846) (1,460) (13,996) (2,619)Other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 417 263 788 2,066

54,232 6,414 153,615 12,644Expenses:

Operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,802 2,091 29,719 2,907Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,078 416 7,554 642General and administration . . . . . . . . . . . . . . . . . . . . . . . . 1,806 563 5,009 1,941Stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . 737 232 2,007 593Depletion, depreciation and accretion . . . . . . . . . . . . . . . . 31,243 5,745 85,291 8,661

47,666 9,047 129,580 14,744

Income (loss) before taxes . . . . . . . . . . . . . . . . . . . . . . . . . . 6,566 (2,633) 24,035 (2,100)Future taxes (reduction) . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,043 (552) 6,736 (348)

Net income (loss) before non-controlling interest . . . . . . . 4,523 (2,081) 17,299 (1,752)Non-controlling interest (note 7) . . . . . . . . . . . . . . . . . . . . 60 — 154 —

Net income (loss) and comprehensive income (loss) . . . . . 4,463 (2,081) 17,145 (1,752)Retained earnings (deficit), beginning of period . . . . . . . . 10,999 767 (1,683) 438

Retained earnings (deficit), end of period . . . . . . . . . . . . . $15,462 $(1,314) $ 15,462 $ (1,314)

Income (loss) per share: (note 8)Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.04 $ (0.03) $ 0.15 $ (0.03)

Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.04 $ (0.03) $ 0.14 $ (0.03)


FS-3


INTERIM CONSOLIDATED STATEMENTS OF CASH FLOW

(Unaudited) Three Months Ended Nine Months Ended

(000s)September 30,

2010September 30,

2009September 30,

2010September 30,

2009

Cash provided by (used in):Operations:

Net income (loss) for the period . . . . . . . . . . . . . . . . . . . . . $ 4,463 $ (2,081) $ 17,145 $ (1,752)Items not involving cash:

Depletion, depreciation and accretion . . . . . . . . . . . . . . 31,243 5,745 85,291 8,661Stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . 737 232 2,007 593Future taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,043 (552) 6,736 (348)

Unrealized gain on financial instruments . . . . . . . . . . . . . . (6,818) — (21,637) —Realized gain on sale of investments . . . . . . . . . . . . . . . . . — — (45) —Non-controlling interest . . . . . . . . . . . . . . . . . . . . . . . . . . . 60 — 154 —Changes in non-cash operating working capital . . . . . . . . . 9,435 3,987 8,348 1,720

Cash flow from operations . . . . . . . . . . . . . . . . . . . . . . . . . 41,163 7,331 97,999 8,874

Financing:Issue of common shares . . . . . . . . . . . . . . . . . . . . . . . . . . . 25,300 — 249,380 140,000Share issue costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,098) (6) (10,536) (5,698)Increase in bank debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35,961 — 34,636 —Repayment of long-term obligation . . . . . . . . . . . . . . . . . . (621) — (621) —

Cash flow from financing . . . . . . . . . . . . . . . . . . . . . . . . . . 59,542 (6) 272,859 134,302

Investing:Exploration and development . . . . . . . . . . . . . . . . . . . . . . . (147,277) (48,046) (327,360) (73,511)Property acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (17,116) (187,050) (289,400) (300,545)Corporate acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 744 (3,156) 744Property dispositions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11,971 — 21,834 —Proceeds from sale of investment . . . . . . . . . . . . . . . . . . . . — — 255 —Changes in non-cash working capital . . . . . . . . . . . . . . . . . 51,717 8,508 27,180 22,716

Cash flow used in investing . . . . . . . . . . . . . . . . . . . . . . . . (100,705) (225,844) (570,647) (350,596)

Changes in cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — (218,519) (199,789) (207,420)Cash, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . — 323,238 199,789 312,139

Cash end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ 104,719 $ — $ 104,719

Cash is defined as cash and cash equivalents.


FS-4


NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the three and nine months ended September 30, 2010 and 2009(tabular amounts in thousands of dollars, unless otherwise noted)

1. INCORPORATION

Tourmaline Oil Corp. (the “Company”) was incorporated under the laws of the Province of Alberta on July 21,2008. The Company is engaged in the acquisition, exploration, development and production of petroleum and naturalgas properties.

The interim financial statements have been prepared by management in accordance with Canadian generallyaccepted accounting principles (“GAAP”), following the same accounting policies and methods of computation as theconsolidated financial statements for the year ended December 31, 2009. The following disclosure is incremental to thedisclosure included with the audited annual consolidated financial statements. These unaudited interim consolidatedfinancial statements should be read in conjunction with the consolidated financial statements and notes thereto of theCompany for the year ended December 31, 2009.

Certain comparative amounts have been restated to conform to current presentation.

2. PROPERTY, PLANT AND EQUIPMENT

As at September 30, 2010 Cost

AccumulatedDepletion/

DepreciationNet BookValue

Petroleum and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,564,873 $106,924 $1,457,949Furniture, fixtures and leasehold improvements . . . . . . . . . . . . . . . . . . . . . . . . 1,162 293 869

$1,566,035 $107,217 $1,458,818

As at December 31, 2009 Cost



Petroleum and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 776,767 $ 22,616 $ 754,151Furniture, fixtures and leasehold improvements . . . . . . . . . . . . . . . . . . . . . . . . 777 130 647

$ 777,544 $ 22,746 $ 754,798

The costs of unproved properties, exploration expenditures and seismic costs at September 30, 2010 of $391.4million (December 31, 2009 – $233.0 million) have been excluded from the depletion calculation. Future developmentcosts for the period ended September 30, 2010 of $393.4 million (December 31, 2009 – $228.9 million) were includedin the depletion calculation.

General and administrative expenditures for the period ended September 30, 2010 of $6.6 million (December 31,2009 – $3.2 million) have been capitalized and included as costs of petroleum and natural gas properties. Included inthis amount are the non-cash related stock-based compensation of $1.7 million (December 31, 2009 – $0.9 million) andthe associated future tax liability of $0.6 million (December 31, 2009 – $0.3 million).

Tourmaline has spent $289.4 million on property acquisitions to September 30, 2010. As part of the propertyacquisitions, the Company assumed a long-term obligation of $19.9 million and asset retirement obligations of $2.5million.

Tourmaline has also disposed of some producing and non-producing properties to date, for proceeds of $25.1million. Included in the proceeds was an investment in a private corporation valued at $3.25 million.

During the third quarter Tourmaline acquired a 20% working interest in a gas processing facility in the DeepBasin for consideration of $11.8 million.

As at September 30, 2010, the Company applied a ceiling test to its property, plant and equipment and determinedthat no impairment has occurred.

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Corporate Acquisitions

Altia Energy Ltd.

On January 14, 2010, Tourmaline acquired all of the issued and outstanding shares of Altia Energy Ltd. (“Altia”).As consideration, Tourmaline paid cash of $2.7 million before transaction costs of $2.0 million and issued 6,411,669common shares at a price of $15.00 per share. The operations of Altia have been included with the results of theCompany commencing January 14, 2010.

Each of the corporate transactions has been accounted for by the purchase method based on fair values as follows:

2010 Acquisition 2009 Acquisitions

Altia Energy Ltd.Vigilant

Exploration Inc. Exshaw Oil Corp.Pienza Petroleum

Inc.

Net assets acquired:Property, plant and equipment . . . . . . . . . . . . . . $126,127 $29,467 $163,847 $43,399Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,516 10,314 299 8,091Working capital . . . . . . . . . . . . . . . . . . . . . . . . . (461) (153) (8,840) 652Long-term investment . . . . . . . . . . . . . . . . . . . . — 678 — —Long-term bank debt . . . . . . . . . . . . . . . . . . . . . (6,550) — (2,261) —Asset retirement obligations . . . . . . . . . . . . . . . (612) (662) (1,803) (278)Future taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . (19,173) 7,834 (5,967) (1,881)Non-controlling interest . . . . . . . . . . . . . . . . . . . — — (13,498) —

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $100,847 $47,478 $131,777 $49,983

Consideration:Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,664 $ 149 $ — $ 6,000Shares issued . . . . . . . . . . . . . . . . . . . . . . . . . . . 96,175 46,050 130,502 42,637Transaction costs . . . . . . . . . . . . . . . . . . . . . . . . 2,008 1,279 1,275 1,346

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $100,847 $47,478 $131,777 $49,983

The above amounts are estimates based on information available to the Company at the time of preparation ofthese financial statements. Accordingly, these amounts are subject to changes as cost estimates and values arefinalized.

3. INVESTMENTS

As part of an asset disposition in the second quarter of 2010, Tourmaline received common shares of a privatecorporation valued at $3.25 million. Tourmaline also owns common shares of a public junior oil and gas companywhich have been fair-valued at $0.5 million based on the quoted market price at quarter end.

A reconciliation of the investments is provided below:



Balance, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 632 $ —Acquired on corporate acquisition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 678Proceeds on disposition of shares (net of realized gain of $45,000) . . . . . . . . . . (210) —Acquired on asset disposition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,250 —Unrealized gain (loss) on investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73 (46)

Balance, end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $3,745 $632

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4. ASSET RETIREMENT OBLIGATIONS

The Company’s asset retirement obligations result from net ownership interests in petroleum and natural gasassets including well sites, gathering systems and processing facilities. The Company estimates the total undiscountedamount of cash flows required to settle its asset retirement obligations is approximately $48 million (December 31,2009 – $30 million), which will be incurred between 2021 and 2027. A credit-adjusted risk-free rate of 10% and aninflation rate of 3% were used to calculate the fair value of the asset retirement obligations.

A reconciliation of the asset retirement obligations is provided below:



Balance, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 7,208 $ —Liabilities incurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,041 698Liabilities incurred on corporate acquisitions (note 2) . . . . . . . . . . . . . . . . . . . . 612 2,743Liabilities incurred on property acquisitions (note 2) . . . . . . . . . . . . . . . . . . . . 2,508 3,481Accretion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 820 286

Balance, end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $12,189 $7,208

5. BANK DEBT

The Company has a financing arrangement with two Canadian chartered banks for an extendible revolving termloan in the amount of $100 million, in addition to a $15 million operating line. The facility bears interest on a variablegrid currently 250 basis points over the prevailing banker’s acceptance rate. Security for the facility includes a generalsecurity agreement and a $500 million demand loan debenture secured by a first floating charge over all assets. OnJuly 31, 2011, at the Company’s discretion, the facility is available on a non-revolving basis for a period of 365 days, atwhich time the facility would be due and payable. Alternatively, the facility may be extended for a further 364-dayperiod at the request of the Company and subject to approval by the bank.

A subsidiary of the Company also has a financing arrangement with a Canadian chartered bank for an extendiblerevolving term loan in the amount of $5 million in addition to a $5 million operating line. The interest rate chargedvaries based on the amount outstanding. Security for the facility includes a general security agreement and a demandloan debenture secured by a first floating charge over all of the subsidiary’s assets. The revolving term credit facilityhas a 364-day extendible period plus a one-year maturity.

The Company is required to meet certain financial-based covenants to maintain the facilities. The financialcovenants include a requirement to ensure the total amount drawn on the facility does not exceed the total borrowingbase as defined in each facility’s agreement, and that the ratio of earnings adjusted for interest, taxes and other non-cash items to interest expense does not exceed a predetermined amount, as determined by each facility’s agreement. Asat September 30, 2010 the Company was in compliance with these covenants.

As at September 30, 2010, the companies have drawn down on existing facilities in the amount of $41.2 million(December 31, 2009 – nil).

6. LONG TERM OBLIGATION

As part of the June 2010 acquisition of petroleum and natural gas properties, the Company acquired a firmtransportation agreement. A $19.9 million liability was recorded to account for the fair value of the agreement at thetime of the acquisition. This amount was accounted for as part of the acquisition cost and will be charged as a reductionto transportation expenses over the life of the contracts as they are incurred. The current portion of this obligation is$3.7 million. The charge for the three and nine months ended September 30, 2010 was $0.6 million.

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7. NON-CONTROLLING INTEREST

On November 10, 2009, Tourmaline acquired 90.6 percent of Exshaw Oil Corp., a private company engaged in oiland gas exploration in Canada.

A reconciliation of the non-controlling interest is provided below:



Balance, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $13,526 $ —Recorded as of the acquisition date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 13,498Share of subsidiary’s net income for the period . . . . . . . . . . . . . . . . . . . . . . . . . 154 28

Balance, end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $13,680 $13,526

8. SHARE CAPITAL

(a) Authorized

Unlimited number of Common Shares, without par value.

Unlimited number of non-voting Preferred Shares, issuable in series.

(b) Common shares issued



($’s in 000s) Number of Shares Amount Number of Shares Amount

Balance, beginning of period . . . . . . . . . . . . . . . . . . . . . . . 101,809,391 $ 895,095 53,000,001 $319,858Issued on corporate acquisition . . . . . . . . . . . . . . . . . . . 6,411,669 96,175 18,265,766 219,189For cash on private placement of common shares . . . . . 9,500,000 171,000 25,793,624 316,904For cash on private placement of flow-through

common shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,600,000 78,220 1,750,000 31,500Issued for the acquisition of properties . . . . . . . . . . . . . 2,500,000 45,000 3,000,000 24,000For cash on exercise of stock options . . . . . . . . . . . . . . 20,000 160 — —Contributed surplus on exercise of stock options . . . . . — 188 — —Share issue costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — (10,536) — (13,819)Tax effect of share issue costs . . . . . . . . . . . . . . . . . . . . — 2,729 — 3,713Tax effect of flow-through renunciations . . . . . . . . . . . — (7,875) — (6,250)

Balance, end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123,841,060 $1,270,156 101,809,391 $895,095

On January 14, 2010, the Company issued 6.4 million common shares, at $15.00 per share, as part of theconsideration of a corporate acquisition (note 2).

On March 19, 2010, the Company issued 9.5 million common shares at $18.00 per share, for gross proceeds of$171 million, and 2.45 million flow-through common shares at $21.60 per share, for gross proceeds of $52.9 million.These issuances included a non-brokered component where insiders purchased 1.5 million common shares and0.45 million flow-through common shares.

Tourmaline issued 2.5 million common shares at $18.00 per share as part of the consideration of a propertyacquisition which closed June 1, 2010.

On August 12, 2010, the Company issued 1.15 million flow-through common shares of $22.00 per share, for grossproceeds of $25.3 million.

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(c) Stock options

The Company has a rolling stock option plan. Under the employee stock option plan, the Company may grantoptions to its employees for up to 12,384,106 shares of common stock. The exercise price of each option equals themarket price of the Company’s stock on the date of grant and the option’s maximum term is five years. Options aregranted throughout the year and vest 1/3 on each of the first, second and third anniversaries from the date of grant.

Number of optionsWeighted average

exercise price

Stock options outstanding, December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,850,000 $ 7.00Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,935,000 12.24Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (175,000) 7.43

Stock options outstanding, December 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,610,000 9.99

Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,182,000 17.69Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (20,000) 8.00

Stock options outstanding, September 30, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11,772,000 $12.08

The following table summarizes stock options outstanding and exercisable at September 30, 2010.

Range of exercise price

Numberoutstanding atperiod end

Weighted averageremaining

contractual lifeWeighted average

exercise priceNumber exercisable

at period endWeighted average

exercise price

$7.00 - $8.00 . . . . . . . . . . . . . . 3,995,000 3.15 $ 7.09 1,318,333 $ 7.08$10.00 - $15.00 . . . . . . . . . . . . 5,085,000 3.95 12.77 808,333 10.32$16.68 - $18.35 . . . . . . . . . . . . 2,692,000 4.83 18.18 — —

11,772,000 3.88 $ 7.92 2,126,667 $ 8.31

The fair value of options granted was estimated on the date of grant using the Black-Scholes option-pricing modelwith the following weighted average assumptions and resulting values for the period ended:

September 30, 2010 September 30, 2009

Fair value of options granted (weighted average) . . . . . . . . . . . . . . . . . . . . . . . . . $ 5.35 $ 1.46Risk free interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.43% 2.59%Estimated hold period prior to exercise . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 years 5 yearsExpected volatility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40% NilDividend per share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.00 $ 0.00

(d) Contributed surplus

The following table reconciles contributed surplus:



Balance, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,018 $ 136Capitalized stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,704 873Expensed stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,007 1,009Exercise of stock options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (188) —


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(e) Per share amounts

The following summarizes the common shares used in calculating per share amounts:

Three Months EndedSeptember 30, 2010


Weighted average shares outstanding:Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123,303,560 117,839,772Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126,871,561 121,106,729

9. FINANCIAL RISK MANAGEMENT

The Board of Directors has overall responsibility for the establishment and oversight of the Company’s riskmanagement framework. The Board has implemented and monitors compliance with risk management policies.

The Company’s risk management policies are established to identify and analyze the risks faced by the Company,to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company’sactivities.

(a) Fair value of financial instruments

Financial instruments comprise cash and cash equivalents, accounts receivable, investments, accounts payable andaccrued liabilities, commodity risk management contracts and bank debt. The fair values of cash and cash equivalents,accounts receivable and accounts payable and accrued liabilities approximate their carrying amounts due to their short-term maturities. The Company’s investments held for trading were fair valued at September 30, 2010 and wereclassified as Level 1.

The fair value of the risk management contracts (as presented on the balance sheet) are determined by discountingthe difference between the contracted price and published forward price curves as at the balance sheet date, using theremaining contracted oil and natural gas volumes, and are considered Level 2.

Bank debt bears interest at a floating market rate and accordingly the fair value approximates the carrying value.

(b) Credit risk

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument failsto meet its contractual obligations, and arises principally from the Company’s receivables from joint venture partners,petroleum and natural gas marketers and commodity price risk contracts. As at September 30, 2010, Tourmaline’sreceivables consisted of $19.5 million (December 31, 2009 – $13.7 million) from joint venture partners, $16.7 million(December 31, 2009 – $11.1 million) from petroleum and natural gas marketers and $16.8 million (December 31, 2009– $20.3 million) from provincial and federal governments.

Receivables from petroleum and natural gas marketers are normally collected on the 25th day of the monthfollowing production. The Company’s policy to mitigate credit risk associated with these balances is to establishmarketing relationships with creditworthy purchasers. The Company historically has not experienced any collectionissues with its petroleum and natural gas marketers. Joint venture receivables are typically collected within one to threemonths of the joint venture bill being issued to the partner. The Company attempts to mitigate the risk from jointventure receivables by obtaining partner approval of significant capital expenditures prior to expenditure. However, thereceivables are from participants in the petroleum and natural gas sector, and collection of the outstanding balances isdependent on industry factors such as commodity price fluctuations, escalating costs and the risk of unsuccessfuldrilling. In addition, further risk exists with joint venture partners as disagreements occasionally arise that increase thepotential for non-collection. The Company does not typically obtain collateral from petroleum and natural gasmarketers or joint venture partners; however, the Company does have the ability to withhold production from jointventure partners in the event of non-payment.

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The Company monitors the age of and investigates issues behind its receivables that have been past due for over60 days. At September 30, 2010, the Company had $2.5 million (December 31, 2009 – $251,000) over 90 days. TheCompany is satisfied that these amounts are substantially collectible.

The carrying amount of accounts receivable and cash and cash equivalents represents the maximum creditexposure. The Company does not have an allowance for doubtful accounts as at September 30, 2010 (December 31,2009 – nil) and did not provide for any doubtful accounts nor was it required to write-off any receivables during theperiod ended September 30, 2010 (December 31, 2009 – nil).

(c) Liquidity risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they come due.The Company’s approach to managing liquidity is to ensure, as far as possible, that it will have sufficient liquidityto meet its liabilities when due, under both normal and stressed conditions without incurring unacceptable lossesor risking harm to the Company’s reputation.

The Company’s accounts payable and accrued liabilities balance at September 30, 2010 is approximately $134.1million (December 31, 2009 – $86.9 million). It is the Company’s policy to pay suppliers within 45-75 days. Theseterms are consistent with industry practice. As at September 30, 2010, substantially all of the account balances are lessthan 90 days.

The Company prepares annual capital expenditure budgets, which are regularly monitored and updated asconsidered necessary. Further, the Company utilizes authorizations for expenditures on both operated and non-operatedprojects to further manage capital expenditures. The Company also attempts to match its payment cycle with collectionof petroleum and natural gas revenues on the 25th of each month.

(d) Market risk


Currency risk has minimal impact on the value of the financial assets and liabilities on the balance sheet atSeptember 30, 2010. Changes in the US to Canadian exchange rate, however, could influence future petroleum andnatural gas prices which could impact the value of certain derivative contracts. This influence cannot be accuratelyquantified.

Interest rate risk has minimal impact on the Company at the balance sheet date as there was a nominal averageamount of cash in short term investments and only small amounts drawn on the credit facilities over the period. At theend of the third quarter there was a draw on the Company’s credit facilities of $41.2 million, which will expose theCompany to interest rate risk via fluctuations in floating rate of interest on a go-forward basis.

Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes incommodity prices. As at September 30, 2010, the Company has entered into certain financial derivative and physicaldelivery sales contracts in order to manage commodity risk. These instruments are not used for trading or speculativepurposes. The Company has not designated its financial derivative contracts as effective accounting hedges, eventhough the Company considers all commodity contracts to be effective economic hedges. As a result, all suchcommodity contracts are recorded on the balance sheet at fair value, with changes in the fair value recognized inpetroleum and natural gas sales, settlements are recognized in petroleum and natural gas sales at the time eachtransaction under a contract is settled.

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The Company has entered into the following contracts as at September 30, 2010:


AECO/Nymex Differential Swap 3,000 mmbtu/d January – October 2010 Nymex less $0.44/mmbtuAECO/Nymex Differential Swap 5,000 mmbtu/d April – October 2010 Nymex less $0.35/mmbtuNymex Settlement Price 100 bbls/d January – December 2010 $83.75 US/bblNymex Settlement Price 100 bbls/d January – December 2011 $87.85 US/bblAECO Fixed Price 3,000 gjs/d January – December 2010 $5.63 Cdn/gjAECO Fixed Price 3,000 gjs/d April 2010 – March 2011 Cdn $5.77/gjAECO Fixed Price 2,000 gjs/d April 2010 – March 2011 Cdn $5.72/gjAECO Fixed Price 3,000 gjs/d January – December 2011 Cdn $5.75/gjAECO Fixed Price 3,000 gjs/d January – December 2011 Cdn $5.84/gjAECO Fixed Price 4,000 gjs/d February 2010 – December 2011 Cdn $5.68/gjAECO Fixed Price 2,000 gjs/d February 2010 – December 2011 Cdn $5.72/gjAECO Fixed Price 2,000 gjs/d November 2010 – March 2011 Cdn $6.01/gj averageAECO Fixed Price 2,000 gjs/d March 2010 – March 2012 Cdn $5.72/gj averageAECO Fixed Price 2,000 gjs/d March 2010 – December 2011 Cdn $5.705/gjAECO Call Option 3,000 gjs/d January – December 2011 Cdn $6.50/gj strike priceAECO Fixed Price 3,000 gjs/d March 2010 – March 2011 Cdn $5.89/gjAECO/Nymex Differential Swap 3,000 mmbtu/d November 2010 – October 2011 Nymex less $0.475/mmbtuCostless Collar 100 bbls/d September 2010 – August 2012 US$75/bbl floor

US$96.00/bbl ceilingAECO Call Option 3,000 gjs/d January 2011 – December 2012 Cdn $6.00/gj strike priceAECO Fixed Price 3,000 gjs/d January 2011 – December 2012 Cdn $5.53/gjAECO/Nymex Differential Swap 5,000 mmbtu/d November 2010 – November 2012 Nymex less $0.62/mmbtuAECO/Nymex Differential Swap 5,000 mmbtu/d November 2010 – October 2011 Nymex less $0.485/mmbtuAECO/Nymex Differential Swap 3,000 mmbtu/d November 2010 – October 2012 Nymex less $0.535/mmbtu

The fair value of the outstanding contracts at September 30, 2010 totals $21.9 million, $16.6 million of which iscurrent.

The Company entered in to the following contracts subsequent to September 30, 2010:


AECO/Nymex Differential Swap 5,000 mmbtu/d January – December 2011 Nymex less $0.475/mmbtuFinancial Swap 100 bb/s/d July, 2011 – December 2012 90.00 USD/bbl

The following table provides a summary of the unrealized gains and losses on financial instruments for the periodended September 30, 2010 (September 30, 2009 – nil):

Three Months EndedSeptember 30, 2010


Unrealized gain (loss) on financial instruments . . . . . . . . . . . . . . . . . . . . . . . $6,827 $21,564Unrealized gain (loss) on investments held for trading . . . . . . . . . . . . . . . . . . (9) 73

Unrealized gain (loss) on financial instruments . . . . . . . . . . . . . . . . . . . . . . . $6,818 $21,637

The unrealized gain on derivative contracts has been included on the balance sheet with changes in the fair valueincluded in the unrealized gain on financial instruments on the statement of income. As at September 30, 2010, if thefuture strip prices for natural gas were $0.10 per mcf higher and prices for oil were $1.00 per bbl higher, with all othervariables held constant, before-tax earnings for the period would have been $1.6 million lower. An equal and oppositeimpact would have occurred to before-tax earnings and the fair value of the derivative contracts asset had natural gasprices been $0.10 per mcf lower and oil prices $1.00 per bbl lower.

(e) Capital management

The Company’s policy is to maintain a strong capital base so as to maintain investor, creditor and marketconfidence and to sustain the future development of the business. The Company considers its capital structure to

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include shareholders’ equity, bank debt and working capital. In order to maintain or adjust the capital structure, theCompany may, from time to time, issue shares and adjust its capital spending to manage current and projected debtlevels. The annual and updated budgets are approved by the Board of Directors.

The key measures that the Company utilizes in evaluating its capital structure are total debt adjusted forunrealized gains and losses on financial instruments to cash flow from operations (before changes in non-cash workingcapital) and the current credit available from its creditors in relation to the Company’s budgeted capital program. Debtadjusted for unrealized gains and losses on financial instruments to cash flow from operations (before changes innon-cash working capital) represents a measure of the time it is expected to take to pay off the debt (adjusted forunrealized gains and losses on financial instruments) if no further capital expenditures were incurred and if cash flowfrom operations before changes in non-cash working capital in the next year was equal to the amount in the most recentquarter annualized. At September 30, 2010, the Company had negative working capital of $78.3 million, after adjustingfor unrealized gains on financial instruments and future taxes.

Some holders of the shares in the Company are subject to trading restrictions for the earlier of three years from thedate of issue, or until the Company goes public. The Company has not paid or declared any dividends since the date ofincorporation, nor are any contemplated in the foreseeable future.

10. COMMITMENTS

At September 30, 2010, the Company has fully met the $31.5 million flow-through common share issuecommitment undertaken in 2009. The renouncement of these CEE expenses, along with the related future tax effect of$7.9 million, was recognized in the first quarter of 2010.

On March 19, 2010, the Company issued 2.45 million flow-through common shares committing the Company tospend $52.9 million on eligible capital expenditures prior to December 31, 2011, of which $51.7 million has beenexpended to date.

On August 12, 2010, the Company issued 1.15 million flow-through common shares committing the Company tospend $25.3 million on eligible capital expenditures prior to December 31, 2011, none of which has been expended todate.

In the normal course of business, Tourmaline is obligated to make future payments. These obligations representcontracts and other commitments that are known and non-cancellable.

Payments due by year (000s) 2010 2011 2012 2013 2014

Operating leases . . . . . . . . . . . . . . . . . . . . . . $ 587 $ 2,348 $ 2,120 $ 1,758 $ 1,614Flow-through obligation . . . . . . . . . . . . . . . . — 26,493 — — —Firm transportation agreements . . . . . . . . . . 3,522 17,447 17,213 14,901 8,665

$4,109 $46,288 $19,333 $16,659 $10,279

11. SUBSEQUENT EVENTS

On November 1, 2010, Tourmaline acquired certain petroleum and natural gas properties and related assets in theAlberta Deep Basin for a cash purchase price of approximately $52 million, before closing adjustments.

The Company has entered into an underwriting agreement providing for the issue and sale of 10,000,000 commonshares (11,500,000 common shares if the over-allotment option is exercised in full) priced at $21.00 per common sharepursuant to the initial public offering resulting in estimated gross proceeds of $210.0 million less the underwriters’commission of $11.55 million and estimated offering expenses of $3.75 million assuming no exercise of the over-allotment option and resulting in estimated gross proceeds of $241.5 million less the underwriters’ commission of$13,282,500 and estimated offering expenses of $3.75 million assuming the full exercise of the over-allotment option.

The Company has entered into subscription agreements with certain directors and officers providing for the issue,on a private placement basis, of 850,000 common shares priced at $21.00 per share to such directors and officers forgross proceeds of $17.85 million concurrently with the closing of the initial public offering.

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MANAGEMENT’S REPORT

The accompanying financial statements of Tourmaline Oil Corp. are the responsibility of management and havebeen approved by the Board of Directors. The financial statements have been prepared by management in accordancewith generally accepted accounting principles. When alternative accounting methods exist, management has chosenthose it deems most appropriate in the circumstances. Financial statements are not precise since they include certainamounts based on estimates and judgments. Management has determined such amounts on a reasonable basis in orderto ensure that the financial statements are presented fairly, in all material respects. The financial information containedelsewhere in this report has been reviewed to ensure consistency with the financial statements.

Management has established systems of internal controls, which are designed to provide reasonable assurance thatassets are safeguarded from loss or unauthorized use and to produce reliable accounting records for the preparation offinancial information.

The Board of Directors is responsible for ensuring that management fulfills its responsibilities for financialreporting and internal control. It exercises its responsibilities primarily through the Audit Committee. The AuditCommittee has reviewed the financial statements with management and the auditors, and has reported to the Board ofDirectors. The Board of Directors has approved the financial statements.

The financial statements have been audited by KPMG LLP, the external auditors, in accordance with auditingstandards generally accepted in Canada.

(signed) “Michael L. Rose” (signed) “Brian G. Robinson”President and Chief Executive Officer Vice-President, Finance and Chief Financial Officer

Calgary, Alberta

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AUDITOR’S REPORT

To the Directors of Tourmaline Oil Corp.

We have audited the consolidated balance sheets of Tourmaline Oil Corp. as at December 31, 2009 and 2008 andthe consolidated statements of income (loss), comprehensive income (loss) and retained earnings (deficit) and cashflow for the year ended December 31, 2009 and the period from incorporation on July 21, 2008 to December 31, 2008.These financial statements are the responsibility of the Company’s management. Our responsibility is to express anopinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standardsrequire that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free ofmaterial misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosuresin the financial statements. An audit also includes assessing the accounting principles used and significant estimatesmade by management, as well as evaluating the overall financial statement presentation.

In our opinion, these financial statements present fairly, in all material respects, the financial position of theCompany as at December 31, 2009 and 2008 and the results of its operations and its cash flows for the year endedDecember 31, 2009 and the period from incorporation on July 21, 2008 to December 31, 2008 in accordance withCanadian generally accepted accounting principles.


Calgary, CanadaMay 6, 2010 (except for note 12 which is as of November 15, 2010)

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CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED BALANCE SHEETS

As at December 31,

(000s) 2009 2008


Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 199,789 $312,139Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45,129 658Prepaid expenses and deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,534 3,293

248,452 316,090Investments (note 4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 632 —Property, plant and equipment (note 3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 754,798 3,566Future taxes (note 9) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 2,123

$1,003,882 $321,779


Accounts payable and accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 86,938 $ 1,347Asset retirement obligations (note 5) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,208 —Future taxes (note 9) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 780 —Non-controlling interest (note 7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13,526 —Shareholders’ equity:

Share capital (note 8) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 895,095 319,858Contributed surplus (note 8) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,018 136Retained earnings (deficit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,683) 438

895,430 320,432

$1,003,882 $321,779

Commitments (note 11)Subsequent events (note 12)See accompanying notes to the consolidated financial statements.

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CONSOLIDATED STATEMENTS OF INCOME (LOSS),

COMPREHENSIVE INCOME (LOSS) AND RETAINED EARNINGS (DEFICIT)

For the year ended December 31, 2009 and period from July 21, 2008, date of incorporation, to December 31, 2008

(000s) 2009 2008

Revenue:Oil and natural gas sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $36,927 $ —Royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,779) —

32,148 —Unrealized gain on financial instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 278 —Processing and other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60 —Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,641 1,237

35,127 1,237Expenses:

Operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,204 —Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,769 —General and administration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,154 435Stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,009 136Depletion, depreciation and accretion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23,023 9

37,159 580

Income (loss) before taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,032) 657Future taxes (note 9) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61 219

Net income (loss) before non-controlling interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,093) 438Non-controlling interest (note 7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 —

Net income (loss) and comprehensive income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,121) 438Retained earnings, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 438 —

Retained earnings (deficit), end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (1,683) $ 438

Income (loss) per share: (note 8)Basic and diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (0.03) $ 0.02


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CONSOLIDATED STATEMENTS OF CASH FLOW

For the Year ended December 31, 2009 and period from July 21, 2008, date of incorporation, to December 31, 2008

(000s) 2009 2008


Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (2,121) $ 438Items not involving cash:

Depletion, depreciation and accretion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23,023 9Stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,009 136Future taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61 219

Unrealized gain on financial instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (278) —Non-controlling interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 —Changes in non-cash operating working capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (22,236) (280)

Cash flow from operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (514) 522

Financing:Issue of common shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 348,404 326,000Share issue costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (13,819) (8,484)Repayment of long-term bank debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,261) —

Cash flow from financing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 332,324 317,516

Investing:Exploration and development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (147,417) (3,575)Property acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (360,496) —Corporate acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,655 —Change in non-cash working capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55,098 (2,324)

Cash flow used in investing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (444,160) (5,899)

Changes in cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (112,350) 312,139Cash, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 312,139 —

Cash, end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 199,789 $312,139



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For the year ended December 31, 2009 and the period from July 21, 2008, date of incorporation to December 31, 2008(tabular amounts in thousands of dollars, unless otherwise noted)

Incorporation:

Tourmaline Oil Corp. (the “Company”) was incorporated under the laws of the Province of Alberta on July 21,2008. The Company is engaged in the acquisition, exploration, development and production of petroleum and naturalgas properties.

1. SIGNIFICANT ACCOUNTING POLICIES

The consolidated financial statements of the Company have been prepared in accordance with Canadian generallyaccepted accounting principles. The preparation of financial statements requires management to make estimates andassumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilitiesat the date of the financial statements, and revenues and expenses during the reporting period. Actual results coulddiffer from those estimated.

Specifically, the amounts recorded for depletion and depreciation of petroleum and natural gas assets andaccretion of asset retirement obligations are based on estimates. The ceiling test is based on estimates of reserves,production rates, oil and gas prices, future costs and other relevant assumptions. The amounts for stock-basedcompensation are based on estimates of risk-free rates, expected option life and volatility. Future income taxes arebased on estimates as to the timing of the reversal of temporary differences and tax rates currently substantivelyenacted. By their nature, these estimates are subject to measurement uncertainty and the effect on the financialstatements of changes in such estimates in future periods could be significant.

(a) Consolidation

The consolidated financial statements include the accounts of Tourmaline Oil Corp. and its wholly ownedsubsidiaries Pienza Petroleum Inc. and Vigilant Exploration Inc., and Exshaw Oil Corp. of which the Company owns90.6% (note 7). All intercompany transactions and balances have been eliminated.

(b) Cash and cash equivalents

Cash and cash equivalents are comprised of cash and all investments with a maturity date of three months or less.

(c) Investments

Investments are classified as financial assets held for trading. Financial assets held for trading are initiallyrecorded at their fair value with changes in their fair value recognized in net income.

(d) Petroleum and natural gas assets

(i) Capitalized costs

The Company follows the full-cost method of accounting for petroleum and natural gas assets. Under this method,all costs related to the acquisition of, exploration for and development of petroleum and natural gas reserves arecapitalized. These costs include land acquisition costs, geological and geophysical expenditures, rentals and othercarrying charges on undeveloped properties, costs of drilling both productive and nonproductive wells, oil and gasproduction equipment and facilities, asset retirement costs and administration expenses directly related to theacquisition, exploration and development activities. Proceeds from the disposition of oil and natural gas properties areaccounted for as a reduction of capitalized costs, with no gain or loss recognized, unless such disposition would resultin a change greater than 20% in the depletion or depreciation.

(ii) Depletion and depreciation

Depletion of petroleum and natural gas assets and depreciation of production equipment are calculated using theunit-of-production method, based on production volumes before royalties in relation to estimated proved reserves as

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determined by an independent petroleum engineering firm. Natural gas reserves and production are converted toequivalent barrels of oil based upon the relative energy content of six thousand cubic feet of gas to one barrel of oil.The cost of acquisition and evaluation of unproved properties are initially excluded from the depletion calculation. Aseparate impairment test is performed on these assets to determine whether the carrying value exceeds the fair value.Any excess in carrying value over fair value is impairment. When proved reserves are assigned or a property isconsidered to be impaired, the cost of the property or the amount of the impairment will be added to the capitalizedcosts for the calculation of depletion. Plant and facilities are amortized on a straight-line basis over their estimateduseful life. Other assets are amortized based on the declining balance method at a rate of 25%.

(iii) Ceiling test

Petroleum and natural gas assets are evaluated in each reporting period to determine that the carrying amount isrecoverable and does not exceed the fair value of the properties. The carrying amounts are assessed to be recoverablewhen the sum of the undiscounted cash flows expected from the production of proved reserves, the lower of cost andmarket of unproved properties and the cost of major development projects exceeds the carrying amount of the costcentre. When the carrying amount is not assessed to be recoverable, an impairment loss is recognized to the extent thatthe carrying amount of the cost centre exceeds the sum of the discounted cash flows expected from the production ofproved and probable reserves, the lower of cost and market of unproved properties and the cost of major developmentprojects of the cost centre. The cash flows are estimated using expected future product prices and costs and arediscounted using a risk-free interest rate.

(e) Asset retirement obligations

The Company recognizes the asset retirement obligations for the future cost associated with removal, siterestoration and asset retirement costs. The fair value of the liability for the Company’s asset retirement obligation isrecorded in the period in which it is incurred, discounted to its present value using the Company’s credit-adjusted risk-free interest rate and the corresponding amount recognized by increasing the carrying amount of petroleum and naturalgas assets. The asset recorded is depleted on a unit-of-production basis over the life of the reserves. The liabilityamount is increased each reporting period due to the passage of time and the amount of accretion is charged to earningsin the period. Revisions to the estimated timing of cash flows or to the original estimated undiscounted cost could alsoresult in an increase or decrease to the obligation. Actual costs incurred upon settlement of the retirement obligation arecharged against the obligation to the extent of the liability recorded.

(f) Joint interest operations

Substantially all of the Company’s exploration, development and production activities related to oil and gasoperations are conducted jointly with others and, accordingly, the accounts reflect only the Company’s proportionateinterest in such activities.

(g) Revenue recognition

Revenue from the sale of petroleum and natural gas is recognized during the month when title passes to a thirdparty.

(h) Income taxes

The Company uses the asset and liability method of tax allocation accounting. Under this method, future tax assetsand liabilities are determined based on differences between the financial reporting and tax bases of assets andliabilities, and measured using the substantially enacted tax rates and laws that will be in effect when the differencesare expected to reverse.

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(i) Flow-through common shares

The resource expenditure deductions for income tax purposes related to exploratory activities funded by flow-through common shares are renounced to investors in accordance with tax legislation. Future tax liabilities and sharecapital are adjusted by the estimated cost of the renounced tax deductions when the expenditures are renounced.

(j) Stock-based compensation plans

The Company applies the fair value method for valuing stock option grants. Under this method, compensationcost attributable to all share options granted are measured at fair value at the grant and issuance date and expensed overthe vesting period with a corresponding increase to contributed surplus. Upon the exercise of the stock options,consideration received together with the amount previously recognized in contributed surplus is recorded as an increaseto share capital.

(k) Per share information

Basic per share information is computed by dividing income by the weighted average number of common sharesoutstanding for the period. The treasury stock method is used to determine the diluted per share amounts, whereby anyproceeds from the stock options, warrants or other dilutive instruments are assumed to be used to purchase commonshares at the average market price during the period. The weighted average number of shares outstanding is thenadjusted by the net change.

(l) Financial instruments

A financial instrument is any contract that gives rise to a financial asset of one entity and a financial liability orequity instrument to another entity. Upon initial recognition all financial instruments, including all derivatives, arerecognized on the balance sheet at fair value. Subsequent measurement is then based on the financial instruments beingclassified into one of five categories: held for trading, held to maturity, loans and receivables, available for sale andother liabilities. The Company has designated its cash and cash equivalents and its investments as held for tradingwhich are measured at fair value. Accounts receivable are classified as loans and receivables which are measured atamortized cost. Accounts payable and accrued liabilities and long-term bank debt are classified as other liabilitieswhich are measured at amortized cost, which is determined using the effective interest method. The Company willassess at each reporting period whether a financial asset is impaired with any impairment recorded in net income. TheCompany is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates andinterest rates in the normal course of operations. A variety of derivative instruments may be used by the Company toreduce its exposure to fluctuations in commodity prices, foreign exchange rates, and interest rates. The Company doesnot use these derivative instruments for trading or speculative purposes. The Company considers all of thesetransactions to be economic hedges; however, the majority of the Company’s contracts do not qualify or have not beendesignated as hedges for accounting purposes. As a result, all derivative contracts are classified as held for trading andare recorded on the balance sheet at fair value, with changes in the fair value recognized in net income, unless specifichedge criteria are met. The fair values of these derivative instruments are based on an estimate of the amounts thatwould have been received or paid to settle these instruments prior to maturity given future market prices and otherrelevant factors. Proceeds and costs realized from holding the derivative contracts are recognized in net income at thetime each transaction under a contract is settled.

The Company has elected to account for its physical delivery sales contracts, which were entered into andcontinue to be held for the purpose of receipt or delivery of non-financial items in accordance with its expectedpurchase, sale or usage requirements as executory contracts on an accrual basis rather than as non-financial derivatives.

The Company measures and recognizes embedded derivatives separately from the host contracts when theeconomic characteristics and risks of the embedded derivative are not closely related to those of the host contract,when it meets the definition of a derivative and when the entire contract is not measured at fair value. Embedded

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derivatives are recorded at fair value. The Company immediately expenses all transaction costs incurred in relation tothe acquisition of a financial asset or liability. The Company applies trade-date accounting for the recognition of apurchase or sale of cash equivalents, investments and derivative contracts. The significance of inputs used in makingfair value measurements is examined and classified according to a fair value hierarchy. Fair values of assets andliabilities included in Level 1 are determined by reference to quoted prices in active markets for identical assets andliabilities. Assets and liabilities in Level 2 include valuations using inputs other than quoted prices for which allsignificant outputs are observable, either directly or indirectly. Level 3 valuations are based on inputs that areunobservable and significant to the overall fair value measurement.

2. CHANGES IN ACCOUNTING POLICY

Effective December 31, 2009, the Company adopted the CICA amended Section 3862, “Financial Instruments –Disclosures,” to include additional disclosure requirements about fair value measurement for financial instruments andliquidity risk disclosures. These amendments require a three-level hierarchy that reflects the significance of the inputsused in making the fair value measurements. Fair values of assets and liabilities included in Level 1 are determined byreference to quoted prices in active markets for identical assets and liabilities. Assets and liabilities in Level 2 includevaluations using inputs other than quoted prices for which all significant outputs are observable, either directly orindirectly. Level 3 valuations are based on inputs that are unobservable and significant to the overall fair valuemeasurement. The adoption of this policy did not impact the measurement of the amounts reported in the Company’sfinancial statements as they primarily relate to disclosures as further outlined in note 10.

Future Accounting Changes

(a) International Financial Reporting Standards (“IFRS”)

In February 2008, the CICA Accounting Standards Board (“AcSB”) confirmed that the changeover to IFRS fromCanadian GAAP will be required for publicly accountable enterprises for interim and annual financial statementseffective for fiscal years beginning on or after January 1, 2011, including comparatives for 2010. In July 2009 anamendment to IFRS First Time Adoption of International Reporting Standards was issued that applies to oil and gasassets. The amendment will permit the Company to apply IFRS prospectively by utilizing its current reserves at thetransition date to allocate the Company’s full cost pool, with the provision that a ceiling test, under IFRS standards, beconducted at the transition date. The eventual changeover to IFRS represents a change due to new accountingstandards. The transition from current Canadian GAAP to IFRS is a significant undertaking that may materially affectthe Company’s reported financial position and results of operations.

(b) Business combinations

In December 2008, the CICA issued Section 1582, Business Combinations. This section is effective January 1,2011 and applies prospectively to business combinations for which the acquisition date is on or after the first annualreporting period beginning on or after January 1, 2011 for the Company. Early adoption is permitted. This sectionreplaces Section 1581, Business Combination and harmonizes the Canadian standards with IFRS.

(c) Consolidated financial statements and non-controlling interest

In 2009 Section 1601 and Section 1602 were issued which replace the existing guidance under section 1600,Consolidated Financial Statements. These standards provide guidance for preparing consolidated financial statementsand for accounting for non-controlling interest in a subsidiary subsequent to a business combination. These standardsare effective for business combinations occurring on or after January 1, 2011, with early adoption permitted.

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3. PROPERTY, PLANT AND EQUIPMENT




Petroleum and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $776,767 $22,616 $754,151Furniture, fixtures and leasehold improvements . . . . . . . . . . . . . . . . . . . . . . . . . . . 777 130 647

$777,544 $22,746 $754,798




Petroleum and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 3,429 $ — $ 3,429Furniture and fixtures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 146 9 137

$ 3,575 $ 9 $ 3,566

The cost of unproven properties, exploration expenditures and seismic costs at December 31, 2009 of $233.0million (2008 – $3.4 million) have been excluded from the depletion calculation. Future development costs for the yearended December 31, 2009 of $228.9 million (2008 – nil) were included in the depletion calculation.

General and administrative expenditures for the year ended December 31, 2009 of $3.2 million (2008 – nil) havebeen capitalized and included as costs of petroleum and natural gas properties. Included in this amount is the non-cashrelated stock-based compensation of $0.9 million, and the associated future tax liability of $0.3 million.

Tourmaline acquired significant producing assets in 2009 for total consideration of $384.5 million, including cashof $360.5 million and 3.0 million common shares. Included in the property acquisitions are unfavourable fixedunutilized transportation and processing commitments for $3.5 million which expire in February 2010. Thesecommitments have been included in current liabilities as at December 31, 2009 and are being amortized on a straightline basis over the life of the contract. As at December 31, 2009 there were $0.6 million of commitments remaining. Aspart of the property acquisitions, the Company assumed $3.5 million of asset retirement obligations.

As at December 31, 2009, the Company applied a ceiling test to its property, plant and equipment and determinedthat no impairment has occurred. The ceiling test was calculated using the following expected future market prices of:

YearWTI Oil($US/bbl)

AECO Gas(Cdn$/mmbtu)

US$/Cdn$Exchange Rates

2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80.00 5.96 0.952011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83.00 6.79 0.952012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86.00 6.89 0.952013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89.00 6.95 0.952014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92.00 7.05 0.952015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93.84 7.16 0.952016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95.72 7.42 0.952017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97.64 7.95 0.952018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99.59 8.52 0.95

Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . +2.0% +2.0% 0.95

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Corporate Acquisitions

Pienza Petroleum Inc.

On September 15, 2009, Tourmaline acquired all of the issued and outstanding shares of Pienza Petroleum Inc.(Pienza). As consideration, Tourmaline paid cash of $6.0 million before transaction costs of $1.3 million and issued3,553,063 shares at a price of $12.00 per share. The operations of Pienza have been included with the results of theCompany commencing September 15, 2009. The transaction was accounted for by the purchase method based on fairvalues as follows:

(000s)

Net assets acquired:Property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $43,399Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,091Working capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 652Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (278)Future income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,881)

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $49,983

Consideration:Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6,000Shares issued . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42,637Transaction costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,346

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $49,983


Vigilant Exploration Inc.

On November 10, 2009, Tourmaline acquired all of the issued and outstanding shares of Vigilant Exploration Inc.(Vigilant) by issuing 3,837,522 shares at a price of $12.00 per share and $149,000 in cash for total consideration of$46.2 million. The operations of Vigilant have been included with the results of the Company commencingNovember 10, 2009. The transaction was accounted for by the purchase method based on fair values as follows:

(000s)

Net assets acquired:Property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $29,467Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,314Working capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (153)Long-term investment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 678Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (662)Future income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,834

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $47,478

Consideration:Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 149Shares issued . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46,050Transaction costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,279

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $47,478

FS-24





Exshaw Oil Corp.

On November 10, 2009, Tourmaline acquired 90.6 % of the outstanding shares of Exshaw Oil Corp. (Exshaw) byissuing 10,875,181 shares at a price of $12.00 per share for total consideration of $130.5 million. The operations ofExshaw have been included with the results of the Company commencing November 10, 2009. The transaction wasaccounted for by the purchase method based on fair values as follows:

(000s)

Net assets acquired:Property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $163,847Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 299Working capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (8,840)Long-term bank debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,261)Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,803)Future income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5,967)Non-controlling interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (13,498)

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $131,777

Consideration:Shares issued . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $130,502Transaction costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,275

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $131,777


4. INVESTMENTS

Tourmaline owns common shares of a public junior oil and gas company with a fair value of $0.6 million as atDecember 31, 2009. This investment has been accounted for at fair value based on the quoted market price at year end.


The Company’s asset retirement obligations result from net ownership interests in petroleum and natural gasassets including well sites, gathering systems and processing facilities. The Company estimates that the totalundiscounted amount of cash flows required to settle its asset retirement obligations is approximately $30 million,which will be incurred between 2021 and 2026. A credit-adjusted risk-free rate of 10% and an inflation rate of 3% wereused to calculate the fair value of the asset retirement obligations. The Company had no asset retirement obligationrelated to the period ended December 31, 2008.

FS-25




A reconciliation of the asset retirement obligations is provided below:

Balance, December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ —Liabilities incurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 698Liabilities incurred on corporate acquisitions (note 3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,743Liabilities incurred on property acquisitions (note 3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,481Accretion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 286

Balance, December 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $7,208

6. BANK DEBT

The Company has a financing arrangement with two Canadian chartered banks for an extendable revolving termloan in the amount of $15 million in addition to a $5 million operating line. As at December 31, 2009, none of this termloan was drawn. The facility bears interest on a variable grid currently 250 basis points over the prevailing banker’sacceptance rate. Security for the facility includes a general security agreement and a $500 million demand loandebenture secured by a first floating charge over all assets. In November 2010, at the Company’s discretion, the facilityis available on a non-revolving basis for a period of 365 days, at which time the facility would be due and payable.Alternatively, the facility may be extended for a further 364-day period at the request of the Company and subject toapproval by the bank.

A subsidiary of the Company also has a financing arrangement with a Canadian chartered bank for an extendablerevolving term loan in the amount of $5 million in addition to a $5 million operating line. At December 31, 2009, noneof these facilities were drawn (December 31, 2008 – nil). The interest rate charged varies based on the amountoutstanding. Security for the facility includes a general security agreement and a demand loan debenture secured by afirst floating charge over all of the subsidiary’s assets. The revolving term credit facility has a 364-day extendableperiod plus a one-year maturity. The term date of the facility is May 28, 2010.

The Company is required to meet certain financial-based covenants to maintain the both facilities. These financialcovenants include a requirement to ensure the total amount drawn on the facility does not exceed the total borrowingbase as defined in the agreement, and that the ratio of earnings adjusted for interest, taxes and other non-cash items tointerest expense does not exceed a predetermined amount, as determined by each facility’s agreement. As atDecember 31, 2009 the Company was in compliance with these covenants.

7. NON-CONTROLLING INTEREST

On November 10, 2009 Tourmaline acquired 90.6 % of Exshaw Oil Corp., a private company engaged in oil andgas exploration in Canada.

A reconciliation of the non-controlling interest is provided below:

Balance, December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ —Recorded as of the acquisition date (note 3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13,498Share of subsidiary’s net income for the period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Balance, December 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $13,526

8. SHARE CAPITAL

(a) Authorized

Unlimited number of Common Shares without par value.

Unlimited number of non-voting Preferred Shares, issuable in series.

FS-26




(b) Common shares issued

2009 2008

($s in 000s)Number of

Shares AmountNumber of

Shares Amount

Balance, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53,000,001 $319,858 — $ —For cash on initial private placement . . . . . . . . . . . . . . . . . . . . . . . . — — 50,500,001 301,000For cash on private placement of common shares . . . . . . . . . . . . . . 25,793,624 316,904 — —For cash on private placement of flow-through common shares . . . 1,750,000 31,500 2,500,000 25,000Issued for the acquisition of properties . . . . . . . . . . . . . . . . . . . . . . . 3,000,000 24,000 — —Issued on corporate acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18,265,766 219,189 — —Share issue costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (13,819) (8,484)Tax effect of share issue costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,713 2,342Tax effect of flow-through renunciations . . . . . . . . . . . . . . . . . . . . . (6,250) —

Balance, end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101,809,391 $895,095 53,000,001 319,858

On May 28, 2009, the Company closed a common share issuance of 14.0 million shares at $10.00 per share forgross proceeds of $140 million. This issue was done on a private placement basis by a syndicate of underwriters andincluded a non-brokered component where insiders purchased 3.0 million shares. A similar common share issuance of11.8 million shares (2.3 million shares were bought by insiders) at $15.00 per share for gross proceeds of $176.9million and a flow-through common share issuance of 1.75 million shares (0.8 million shares were bought by insiders)at $18.00 per share for gross proceeds of $31.5 million was closed on November 10, 2009.

The Company issued 3.0 million common shares as part of the consideration in an asset acquisition which closedApril 30, 2009. The Company also issued 18.3 million common shares as part of three corporate acquisitions, oneclosing September 15, 2009, and the other two acquisitions closing November 10, 2009 (note 3).

The Company was initially capitalized on October 25, 2008 by a private placement of 35.5 million commonshares at $7.00 per share and 15.0 million founders common shares at $3.50 per share. On December 17, 2008 theCompany issued 2.5 million flow-through common shares at $10.00 per share for gross proceeds of $25.0 million.Certain officers and directors of the Company purchased 1.146 million common shares for total gross proceeds of$11.46 million.

(c) Stock options

The Company has a rolling stock option plan. Under the employee stock option plan, the Company may grantoptions to its employees for up to 10,180,939 shares of common stock. The exercise price of each option equals themarket price of the Company’s stock on the date of grant and the option’s maximum term is five years. Options aregranted throughout the year and vest 1/3 on each of the first, second and third anniversaries from the date of grant.

Number ofOptions

Weighted AverageExercise Price

Stock options outstanding, December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,850,000 $ 7.00Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,935,000 12.24Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (175,000) 7.43

Stock options outstanding, December 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,610,000 $ 9.99

FS-27




The following table summarizes stock options outstanding and exercisable at December 31, 2009.

Range ofexercise price

Numberoutstanding atperiod end


contractual lifeWeighted average

exercise priceNumber exercisable

at period endWeighted average

exercise price

$7.00 - $8.00 4,015,000 3.90 $ 7.09 1,216,667 $7.00$10.00 - $15.00 4,595,000 4.66 12.53 — —

8,610,000 4.31 $ 9.99 1,216,667 $7.00

The fair value of options granted was estimated on the date of grant using the Black-Scholes option-pricing modelwith the following weighted average assumptions and resulting values:

December 31,2009

December 31,2008

Fair value of options granted (weighted average) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1.16 $ 0.82Risk-free interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.48% 2.5%Estimated hold period prior to exercise . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 years 5 yearsExpected volatility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . nil nilDividend per share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.00 $ 0.00

(d) Contributed surplus

The following table reconciles contributed surplus:

Balance, December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 136Capitalized stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 873Expensed stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,009

Balance, December 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,018

(e) Per share amounts

The following summarizes the common shares used in calculating per share amounts:

December 31,2009

December 31,2008

Weighted average shares outstanding:Basic and diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68,460,438 20,228,659

As at December 31, 2009, the Company had approximately 8.6 million (2008 – 3.8 million) outstanding stockoptions that were anti-dilutive.

9. TAXES

The provision for taxes in the consolidated statement of earnings differs from the result that would have beenobtained by applying the combined federal and provincial tax rate to the Company’s income before taxes. Thedifference results from the following items:

(000s) 2009 2008

Earnings/(loss) before taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $(2,032) $ 657Combined federal and provincial tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29.0% 29.5%Computed “expected” tax (recovery)/expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (589) $ 194Increase/(decrease) in taxes resulting from:

Stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 293 40Effect of change in tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 357 (15)

Future taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 61 $ 219

FS-28




The future tax liability/(asset) is comprised of the tax effect of temporary differences and future income taxreductions as follows:

(000s) 2009 2008

Petroleum and natural gas assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $15,747 $ 3Share issue costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5,436) (2,126)Non-capital loss carryforward . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (9,531) —

Balance, end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 780 $(2,123)

At December 31, 2009, the Company had non-capital losses in the amount of approximately $36.4 million. Thenon-capital losses expire between 2011 and 2030.

10. FINANCIAL RISK MANAGEMENT

The Board of Directors has overall responsibility for the establishment and oversight of the Company’s riskmanagement framework. The Board has implemented and monitors compliance with risk management policies.

The Company’s risk management policies are established to identify and analyze the risks faced by the Company,to set appropriate risk limits and controls and to monitor risks and adherence to market conditions and the Company’sactivities.

(a) Fair value of financial instruments

Financial instruments comprise cash and cash equivalents, accounts receivable, accounts payable and accruedliabilities and long-term bank debt. The fair values of cash and cash equivalents, accounts receivable and accountspayable and accrued liabilities approximate their carrying amounts due to their short-term maturities. The Company’sinvestments held for trading had a fair value based on quoted market price at December 31, 2009 and were classified asLevel 1.

The fair value of the risk management contracts (as presented on the balance sheet) is determined by discountingthe difference between the contracted price and published forward price curves as at the balance sheet date, using theremaining contracted oil and natural gas volumes, and are considered Level 2.

(b) Credit risk

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument failsto meet its contractual obligations. It arises principally from the Company’s receivables from joint venture partners andpetroleum and natural gas marketers. As at December 31, 2009 Tourmaline’s receivables consisted of $13.7 millionfrom joint venture partners, $11.1 million from petroleum and natural gas marketers and $20.3 million from provincialgovernments.

Receivables from petroleum and natural gas marketers are normally collected on the 25th day of the monthfollowing production. The Company’s policy to mitigate credit risk associated with these balances is to establishmarketing relationships with creditworthy purchasers. The Company historically has not experienced any collectionissues with its petroleum and natural gas marketers. Joint venture receivables are typically collected within one to threemonths of the joint venture bill being issued to the partner. The Company attempts to mitigate the risk from jointventure receivables by obtaining partner approval of significant capital expenditures prior to expenditure. However, thereceivables are from participants in the petroleum and natural gas sector, and collection of the outstanding balances isdependent on industry factors such as commodity price fluctuations, escalating costs and the risk of unsuccessfuldrilling. In addition, further risk exists with joint venture partners as disagreements occasionally arise that increase the

FS-29




potential for non-collection. The Company does not typically obtain collateral from petroleum and natural gasmarketers or joint venture partners; however the Company does have the ability to withhold production from jointventure partners in the event of non-payment.

The Company monitors the age of and investigates issues behind its receivables that have been past due for over60 days. At December 31, 2009 the Company had $251,000 over 90 days. Tourmaline is satisfied that these amountsare substantially collectible.

The carrying amount of accounts receivable and cash and cash equivalents represents the maximum creditexposure. The Company does not have an allowance for doubtful accounts as at December 31, 2009 (2008 – nil) anddid not provide for any doubtful accounts nor was it required to write-off any receivables during the year endedDecember 31, 2009 (2008 – nil).

(c) Liquidity risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they come due. TheCompany’s approach to managing liquidity is to ensure, as far as possible, that it will have sufficient liquidity to meetits liabilities when due, under both normal and stressed conditions without incurring unacceptable losses or riskingharm to the Company’s reputation.

The Company’s accounts payable and accrued liabilities balance at December 31, 2009 is approximately $86million. It is the Company’s policy to pay suppliers within 45 to 75 days. These terms are consistent with industry. Asat December 31, 2009 none of the account balances is greater than 90 days.

The Company prepares annual capital expenditure budgets, which are regularly monitored and updated asconsidered necessary. Further, the Company utilizes authorizations for expenditures on both operated and non-operatedprojects to further manage capital expenditures. The Company also attempts to match its payment cycle with collectionof petroleum and natural gas revenues on the 25th of each month.

(d) Market risk


Currency risk has minimal impact on the value of the financial assets and liabilities on the balance sheet atDecember 31, 2009. Changes in the US to Canadian exchange rate, however, could influence future petroleum andnatural gas prices which could impact the value of certain derivative contracts. This influence cannot be accuratelyquantified.

The Company is exposed to interest rate risk via fluctuations on its short term investments and its debt facilitieswhich bear a floating rate of interest. A 1% change in the average effective interest rate on cash and short terminvestments would have a $2.6 million impact on before tax earnings, and no impact on interest expense as theCompany did not have any amount drawn on either of its credit facilities at December 31, 2009.

Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes incommodity prices. During the fourth quarter and subsequent to December 31, 2009, the Company has entered intocertain financial derivative and physical delivery sales contracts in order to manage commodity risk. These instrumentsare not used for trading or speculative purposes. The Company has not designated its financial derivative contracts aseffective accounting hedges, even though the Company considers all commodity contracts to be effective economichedges. As a result, all such commodity contracts are recorded on the balance sheet at fair value, with changes in thefair value recognized in petroleum and natural gas sales, settlements are recognized in petroleum and natural gas salesat the time each transaction under a contract is settled.

FS-30




The Company has entered into the following contracts as at December 31, 2009:


AECO/Nymex Differential Swap 3,000 mmbtu/d January – October 2010 Nymex less $0.44/mmbtuAECO/Nymex Differential Swap 5,000 mmbtu/d November 2009 – March 2010 Nymex less $0.25/mmbtuAECO/Nymex Differential Swap 5,000 mmbtu/d April – October 2010 Nymex less $0.35/mmbtuNymex Settlement Price 100 bbls/d January – December 2010 US$83.75/bblNymex Settlement Price 100 bbls/d January – December 2011 US$87.85/bblAECO Fixed Price 3,000 gjs/d January – December 2010 Cdn$5.63/gj ceiling

The following table provides a summary of the gain (loss) on financial instruments for the year endedDecember 31, 2009 (2008 – nil):

000s 2009

Unrealized gain on financial instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $324Unrealized loss on investments held for trading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (46)

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $278

The unrealized gain on derivative contracts has been included on the balance sheet with changes in the fair valueincluded in gain on financial instruments on the statement of income. As at December 31, 2009, if the future stripprices for natural gas were $0.10 per mcf higher and prices for oil were $1.00 per bbl higher, with all other variablesheld constant, before-tax earnings for the period would have been $185,000 lower. An equal and opposite impactwould have occurred to before-tax earnings and the fair value of the derivative contracts asset had natural gas pricesbeen $0.10 per mcf lower and oil prices $1.00 per bbl lower.

The following contracts were entered into subsequent to December 31, 2009:


AECO Fixed Price 3,000 gjs/d April 2010 – March 2011 Cdn$5.77/gjAECO Fixed Price 2,000 gjs/d April 2010 – March 2011 Cdn$5.72/gjAECO Fixed Price 3,000 gjs/d January – December 2011 Cdn$5.75/gjAECO Fixed Price 3,000 gjs/d January – December 2011 Cdn$5.84/gjAECO Fixed Price 4,000 gjs/d February 2010 – December 2011 Cdn$5.68/gjAECO Fixed Price 2,000 gjs/d February 2010 – December 2011 Cdn$5.72/gjAECO Fixed Price 2,000 gjs/d November 2010 – March 2011 Cdn$6.01/gj averageAECO Fixed Price 2,000 gjs/d March 2010 – March 2012 Cdn$5.72/gj averageAECO Fixed Price 2,000 gjs/d March 2010 – December 2011 Cdn$5.705/gjAECO Call Option 3,000 gjs/d January – December 2011 Cdn$6.50/gj strike priceAECO Fixed Price 3,000 gjs/d March 2010 – March 2011 Cdn$5.89/gjAECO/Nymex Differential Swap 3,000 mmbtu/d November 2010 – October 2011 Nymex less $0.475/mmbtuCostless Collar 100 bbls/d September 2010 – August 2012 $75 US/bbl floor

$96 US/bbl ceiling

(e) Capital management

The Company’s policy is to maintain a strong capital base so as to maintain investor, creditor and marketconfidence and to sustain the future development of the business. The Company considers its capital structure toinclude shareholders’ equity, bank debt and working capital. In order to maintain or adjust the capital structure, theCompany may from time to time issue shares and adjust its capital spending to manage current and projected debtlevels. The annual and updated budgets are approved by the Board of Directors.

The key measures that the Company uses in evaluating its capital structure are total debt adjusted for unrealizedgains and losses on financial instruments to cash flow from operations (before changes in non-cash working capital)and the current credit available from its creditors in relation to the Company’s budgeted capital program. Debt adjustedfor unrealized gains and losses on financial instruments to cash flow from operations (before changes in non-cash

FS-31




working capital) represents a measure of the time it is expected to take to pay off the debt (adjusted for unrealizedgains and losses on financial instruments) if no further capital expenditures were incurred and if cash flow fromoperations before changes in non-cash working capital in the next year was equal to the amount in the most recentquarter annualized. At December 31, 2009 the Company was in a positive working capital position of $162 million.

Some holders of the shares in the Company are subject to trading restrictions for the earlier of three years from thedate of issue, or until the Company goes public. The Company has not paid or declared any dividends since the date ofincorporation, nor are any contemplated in the foreseeable future. There were no changes in the Company’s approachto capital management since December 31, 2008.

11. COMMITMENTSAt December 31, 2009 the Company has fully spent the $25.0 million flow-through common share issue

commitment undertaken in 2008. The renouncement of these CEE expenses, along with the related future tax effect of$6.25 million, was recognized in the first quarter of 2009.

During 2009, Tourmaline issued 1.75 million flow-through common shares committing the Company to spend$31.5 million on eligible capital expenditures before December 31, 2010. The Company estimates that it has anobligation remaining in the amount of $29.9 million as at the end of the year.

On March 19, 2010 the Company issued 2.45 million flow-through common shares committing the Company tospend $52.9 million on eligible capital expenditures prior to December 31, 2011.

The Company has extended its current operating lease. Future minimum lease payments for the next 5 years are asfollows:

Payment due by year 2010 2011 2012 2013 2014

Operating lease . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,892 $2,021 $2,039 $1,758 $1,614

12. SUBSEQUENT EVENTSŠ Pienza Petroleum Inc. and Vigilant Exploration Inc. were amalgamated into Tourmaline on January 1, 2010.

Š Tourmaline closed a producing asset acquisition on February 12, 2010, using cash consideration of $40.0million.

Š The Company also purchased all the outstanding shares of a private company by issuing 6.4 million commonshares at a purchase price of $15 per share and $2.7 million in cash for total consideration of $98.8 million.This transaction closed on January 15, 2010.

Š The Company issued 9.5 million common shares at a price of $18.00 per share and 2.45 million commonshares on a flow-through basis at a price of $21.60 per share for total proceeds of $223.9 million. Thisfinancing closed on March 19, 2010.

Š Tourmaline acquired a producing asset in the Greater Hinton area for cash of $230.0 million and 2.5 millionshares for total consideration of $275.0 million. This transaction closed June 1, 2010.

Š On November 1, 2010 Tourmaline acquired certain petroleum and natural gas properties and related assets inthe Alberta Deep Basin for a cash purchase price of approximately $52 million, before closing adjustments.

Š The Company has entered into an underwriting agreement providing for the issue and sale of 10,000,000common shares (11,500,000 common shares if the over-allotment option is exercised in full) priced at$21.00 per common share pursuant to the initial public offering resulting in estimated gross proceeds of$210.0 million less the underwriters’ commission of $11.55 million and estimated offering expenses of $3.75million assuming no exercise of the over-allotment option and resulting in estimated gross proceedsof $241.5 million less the underwriters’ commission of $13,282,500 and estimated offering expenses of$3.75 million assuming the full exercise of the over-allotment option.

Š The Company has entered into subscription agreements with certain directors and officers providing for theissue, on a private placement basis, of 850,000 common shares priced at $21.00 per share to such directorsand officers for gross proceeds of $17.85 million concurrently with the closing of the initial public offering.

FS-32

Pro Forma Consolidated Financial Statements of


As at and for the nine months ended September 30, 2010and for the year ended December 31, 2009

FS-33

TOURMALINE OIL CORP.Pro Forma Consolidated Balance Sheet

As at September 30, 2010(Unaudited)

($000’s)

TourmalineOil Corp.

InitialPublic

Offeringand

ConcurrentPrivate

PlacementPro FormaAdjustments Notes

Pro FormaTourmalineOil Corp.


Cash and cash equivalents . . . . . . . . . . . . . . . . . . . $ — 212,550 (41,186) 2(a)(b) $ 171,364Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . 52,988 — — 52,988Prepaid expenses and deposits . . . . . . . . . . . . . . . . 2,797 — — 2,797Fair value of financial instruments . . . . . . . . . . . . 16,633 — — 16,633

72,418 212,550 (41,186) 243,782Investment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,745 — — 3,745Fair value of financial instruments . . . . . . . . . . . . . . 5,255 — — 5,255Property, plant and equipment . . . . . . . . . . . . . . . . . . 1,458,818 — — 1,458,818

$1,540,236 212,550 (41,186) $1,711,600

LiabilitiesCurrent liabilities:

Accounts payable and accrued liabilities . . . . . . . . $ 134,099 — — $ 134,099Future taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,473 — 3,473

137,572 — — 137,572Asset retirement obligations . . . . . . . . . . . . . . . . . . . 12,189 — — 12,189Bank debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41,186 — (41,186) 2(b) —Long-term obligation . . . . . . . . . . . . . . . . . . . . . . . . . 15,520 — — 15,520Future taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28,930 (3,963) — 24,967Non-controlling interest . . . . . . . . . . . . . . . . . . . . . . . 13,680 — — 13,680

Shareholders’ equityShare capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,270,156 216,513 — 2(a) 1,486,669Contributed surplus . . . . . . . . . . . . . . . . . . . . . . . . 5,541 — — 5,541Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . 15,462 — — 15,462

1,291,159 216,513 — 1,507,672

$1,540,236 212,550 (41,186) $1,711,600

See accompanying notes to pro forma consolidated financial statements.

FS-34

TOURMALINE OIL CORP.Pro Forma Consolidated Statement of Income (Loss)

Nine months ended September 30, 2010(Unaudited)

($000’s)

TourmalineOil Corp. Property 3 Other

Pro FormaAdjustments Notes

Pro FormaTourmalineOil Corp.

Revenues:Oil and natural gas sales . . . . . . . . . . . . . . . . . . . . . $134,304 12,565 6,414 — $153,283Realized gain on financial instruments . . . . . . . . . 10,882 — — — 10,882Unrealized gain on financial instruments . . . . . . . . 21,637 — — — 21,637

166,823 12,565 6,414 — 185,802Royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (13,996) (1,602) (1,237) — (16,835)Other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 788 — — — 788

153,615 10,963 5,177 — 169,755

Expenses:Operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37,273 1,322 452 — 39,047General and administration . . . . . . . . . . . . . . . . . . . 5,009 — — — 5,009Stock-based compensation . . . . . . . . . . . . . . . . . . . 2,007 — — — 2,007Depletion, depreciation and accretion . . . . . . . . . . 85,291 — — 14,093 3(h) 99,384

129,580 1,322 452 14,093 145,447

Income (loss) before taxes . . . . . . . . . . . . . . . . . . . . . 24,035 9,641 4,725 (14,093) 24,308Future taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,736 — — 69 3(j) 6,805

Net income (loss) before non-controlling interest . . . 17,299 9,641 4,725 (14,162) 17,503Non-controlling interest . . . . . . . . . . . . . . . . . . . . . 154 — — — 154

Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 17,145 9,641 4,725 (14,162) $ 17,349

Net income (loss) per share (Note 4):Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.13

Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.13

See accompanying notes to pro forma consolidated financial statements.

FS-35

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FS-36


Notes to Pro Forma Consolidated Financial StatementsAs at and for the nine months ended September 30, 2010 and for the year ended December 31, 2009

(Unaudited)

1. Basis of presentation:

The accompanying unaudited pro forma consolidated balance sheet of Tourmaline Oil Corp. (the “Company” or“Tourmaline”) as at September 30, 2010 and the unaudited pro forma consolidated statements of income (loss) for thenine months then ended and the year ended December 31, 2009 (the “pro forma statements”) have been prepared toreflect the proposed distribution of common shares in the capital of Tourmaline.

The unaudited pro forma statements have been prepared by management in accordance with Canadian generallyaccepted accounting principles. The pro forma statements may not be indicative of the results that actually would haveoccurred if the events reflected therein had been in effect on the dates indicated or of the results which may be obtainedin the future. In preparing these pro forma financial statements, no adjustments have been made to reflect operatingsynergies and administrative cost savings that could result from the operations of the combined assets.

Accounting policies used in the preparation of the pro forma statements are in accordance with those disclosed inTourmaline’s audited consolidated financial statements as at and for the year ended December 31, 2009 and theunaudited interim consolidated financial statements as at and for the nine months ended September 30, 2010.

The pro forma statements have been prepared from information derived from and should be read in conjunctionwith the following:

Š Tourmaline’s audited consolidated financial statements as at and for the year ended December 31, 2009 andunaudited interim consolidated financial statements as at and for the nine months ended September 30, 2010.

Š Pienza Petroleum Inc.’s (“Pienza”) unaudited interim financial statements as at and for the six months endedJune 30, 2009.

Š Exshaw Oil Corp.’s (“Exshaw”) unaudited interim financial statements as at and for the nine months endedSeptember 30, 2009.

Š Vigilant Exploration Inc.’s (“Vigilant”) audited consolidated financial statements as at and for the year endedJune 30, 2009 and both the unaudited interim consolidated financial statements as at and for the six monthsended December 31, 2008 and the three months ended September 30, 2009. These financial statements wereused to construct the financial information for the nine months ended September 30, 2009 as more fullypresented in note 3(c).

Š Altia Energy Ltd.’s (“Altia”) audited financial statements as at and for the year ended March 31, 2009 andboth the unaudited interim financial statements as at and for the nine months ended December 31, 2008 andthe nine months ended December 31, 2009. These financial statements were used to construct the financialinformation for the twelve months ended December 31, 2009 as more fully presented in note 3(d).

Š Property 1 (“Alberta Deep Basin Properties”) unaudited interim schedule of revenue, royalties and operatingexpenses for the three months ended March 31, 2009.

Š Property 2 (“Wild River, Harley, Olsen and Sundance Properties”) unaudited interim schedule of revenues,royalties and operating expenses for the six months ended June 30, 2009.

Š Property 3 (“Greater Hinton Properties”) audited schedule of revenue, royalties and operating expenses forthe year ended December 31, 2009 and unaudited schedule of revenue, royalties and operating expenses forthe three months ended March 31, 2010.

In the opinion of management, the pro forma statements include all the necessary adjustments for a fairpresentation of the ongoing entity in accordance with Canadian generally accepted accounting principles.

FS-37



(Unaudited)

2. Pro forma consolidated balance sheet assumptions and adjustments:

The unaudited pro forma consolidated balance sheet gives effect to the following assumptions and adjustments asif they had occurred on January 1, 2010.

(a) Initial Public Offering and Concurrent Private Placement

The Company has entered into an underwriting agreement providing for the issue and sale of 10,000,000 commonshares (11,500,000 common shares if the over-allotment option is exercised in full) priced at $21.00 per common sharepursuant to the initial public offering resulting in estimated gross proceeds of $210.0 million less the underwriters’commission of $11.55 million and estimated offering expenses of $3.75 million assuming no exercise of the over-allotment option.

The Company has entered into subscription agreements with certain directors and officers providing for the issue,on a private placement basis, of 850,000 common shares priced at $21.00 per share to such directors and officers forgross proceeds of $17.85 million concurrently with the closing of the initial public offering.

(b) Pro forma adjustments

Tourmaline’s bank debt of $41.2 million has been assumed to be repaid with cash from Tourmaline’s financingnoted in note 2(a).

3. Pro forma consolidated statements of income (loss) assumptions and adjustments:

The unaudited pro forma consolidated statements of income (loss) give effect to the following assumptions andadjustments as if they had occurred at January 1, 2009:

(a) Pienza – On September 15, 2009 Tourmaline acquired all of the issued and outstanding shares of Pienza. As aresult, the pro forma consolidated statement of income (loss) has been adjusted, based on the unaudited financialstatements for the six months ended June 30, 2009, with operating results for the period July 1, 2009 toSeptember 15, 2009 included in ‘Other’.

(b) Exshaw – On November 10, 2009 Tourmaline acquired 90.6% of the issued and outstanding shares of Exshaw. Asa result, the proforma consolidated statement of income (loss) has been adjusted, based on the unaudited financialstatements for the nine months ended September 30, 2009, with operating results for the period October 1, 2009 toNovember 10, 2009 included in ‘Other’.

FS-38



(Unaudited)

(c) Vigilant – On November 10, 2009 Tourmaline acquired all of the issued and outstanding shares of Vigilant. As aresult, the pro forma consolidated statement of income (loss) has been adjusted, based on the financial informationfor Vigilant for the nine months ended September 30, 2009 constructed as follows:

($000’s)

Year EndedJune 30,2009

(audited)

Less SixMonths EndedDecember 31,

2008(unaudited)

Add ThreeMonths EndedSeptember 30,

2009(unaudited)

Nine MonthsEnded

September 30,2009

(unaudited)

Revenues:Oil and natural gas sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 8,928 $ 5,476 $ 2,074 $ 5,526Royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,590) (1,295) (419) (714)Other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78 43 9 44

7,416 4,224 1,664 4,856

Expenses:Operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,333 1,187 521 1,667General and administration . . . . . . . . . . . . . . . . . . . . . . . . . . 2,577 1,859 899 1,617Stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . (20) — 612 592Depletion, depreciation and accretion . . . . . . . . . . . . . . . . . 5,682 2,591 2,162 5,253

10,572 5,637 4,194 9,129

Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (3,156) $(1,413) $(2,530) $(4,273)

Operating results for the period October 1, 2009 to November 10, 2009 have been included in ‘Other’.

(d) Altia – On January 14, 2010 Tourmaline acquired all of the issued and outstanding shares of Altia. As a result, thepro forma consolidated statement of income (loss) has been adjusted, based on the financial information for Altiafor the twelve months ended December 31, 2009 constructed as follows:

($000’s)

Year EndedMarch 31,

2009(audited)

Less NineMonths EndedDecember 31,

2008(unaudited)

Add NineMonths EndedDecember 31,

2009(unaudited)

Year EndedDecember 31,

2009(unaudited)

Revenues:Oil and natural gas sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . $21,722 $17,064 $ 7,443 $12,101Royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,656) (3,631) (1,118) (2,143)Other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 8 2 (2)

17,070 13,441 6,327 9,956

Expenses:Operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,169 1,586 977 1,560General and administration . . . . . . . . . . . . . . . . . . . . . . . . . . 977 644 949 1,282Stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . 57 49 228 236Depletion, depreciation and accretion . . . . . . . . . . . . . . . . . . 11,082 7,962 6,233 9,353

14,285 10,241 8,387 12,431

Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,785 $ 3,200 $(2,060) $ (2,475)

Operating results for the period January 1, 2010 to January 14, 2010 have been included in ‘Other’ in theSeptember 30, 2010 pro forma consolidated statement of income (loss).

(e) Property 1 (Alberta Deep Basin Properties) – Effective April 1, 2009, the Company entered into an agreement topurchase petroleum and natural gas assets located in the Alberta Deep Basin for $102 million. As a result,

FS-39



(Unaudited)

petroleum and natural gas sales revenue, royalties and operating expenses have been adjusted, based on theunaudited accounting records for the three months ended March 31, 2009, with operating results for the periodApril 1, 2009 to April 30, 2009 included in ‘Other’.

(f) Property 2 (Wild River, Harley, Olsen and Sundance Properties) – Effective July 1, 2009, the Company enteredinto an agreement to purchase petroleum and natural gas assets located in the Alberta Deep Basin for $145million. As a result, petroleum and natural gas sales revenue, royalties and operating expenses have been adjusted,based on the unaudited accounting records for the six months ended June 30, 2009, with operating results for theperiod July 1, 2009 to August 28, 2009 included in ‘Other’.

(g) Property 3 (Greater Hinton Properties) – Effective March 1, 2010, the Company entered into an agreement topurchase petroleum and natural gas assets located in the Alberta Deep Basin for $275 million. As a result,petroleum and natural gas sales revenue, royalties and operating expenses have been adjusted, based on thestatements of revenue, royalties and operating expenses for the year ended December 31, 2009 and the unauditedstatements of revenue, royalties and operating expenses for the three months ended March 31, 2010, withoperating results for the period April 1, 2010 to May 30, 2010 included in ‘Other’ on the September 30, 2010 proforma consolidated statement of income (loss).

(h) Depletion, depreciation and accretion has been adjusted to reflect the application of the appropriateunit-of-production rate for Tourmaline based on the estimated proved petroleum and natural gas reserves asdetermined by independent reserve engineers after adjusting for the transactions described above.

(i) Included in the ‘Other’ column are the unaudited operating results from the corporate and significant propertyacquisitions for periods outside that which have been disclosed in the financial statements and schedules ofrevenue, royalties and operating expenses.

(j) The future income tax provision has been adjusted to reflect the transactions described above.

4. Pro forma common shares outstanding:

The net income (loss) per common share has been based on the following:

Nine monthsended

September 30, 2010

Year endedDecember 31,

2009

Common shares

Weighted average Tourmaline basic shares outstanding . . . . . . . . . . . . . . . . . . . . . . . . 117,839,771 68,460,438Weighted average shares issued on acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,688,102 25,008,144Common shares issued on the initial public offering and concurrent private

placement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,850,000 10,850,000

Weighted average common shares – basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130,377,873 104,318,582Dilutive options outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,266,957 —

Weighted average common shares – diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133,644,830 104,318,582

Pro forma earnings per share

Nine monthsended

September 30, 2010

Year endedDecember 31,

2009

Net income (loss) per share – basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $0.13 $(0.13)Net income (loss) per share – diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $0.13 $(0.13)

FS-40

KPMG LLPChartered Accountants Telephone (403) 691-80002700-205 5 Avenue SW Telefax (403) 691-8008Calgary AB T2P 4B9 Internet www.kpmg.ca

AUDITORS’ REPORT

To The Directors of Tourmaline Oil Corp.

We have audited the schedule of revenues, royalties and operating expenses for the year ended December 31,2008 for Alberta Deep Basin Properties. This financial information is the responsibility of the Company’smanagement. Our responsibility is to express an opinion on this financial information based on our audit.

We conducted our audit in accordance with Canadian generally accepted auditing standards. Those standardsrequire that we plan and perform an audit to obtain reasonable assurance whether the financial information is free ofmaterial misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosuresin the financial information. An audit also includes assessing the accounting principles used and significant estimatesmade by management, as well as evaluating the overall financial information presentation.

In our opinion, this financial information presents fairly, in all material respects, the revenues, royalties andoperating expenses for Alberta Deep Basin Properties for the year ended December 31, 2008 in accordance withCanadian generally accepted accounting principles.

(signed) “KPMG LLP”

Chartered Accountants

Calgary, CanadaOctober 9, 2009

KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMGnetwork of independent member firms affiliated with KPMG International, a Swiss cooperative.

KPMG Canada provides services to KPMG LLP.

FS-41

Alberta Deep Basin Properties

Schedule of Revenue, Royalties and Operating Expenses

Three Months EndedMarch 31

Twelve Months EndedDecember 31

2009(unaudited)

2008(unaudited)

2008(audited)

2007(unaudited)

REVENUES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4,166,371 10,987,114 $42,111,120 $30,484,315ROYALTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,144,692) (1,505,979) (7,624,601) (7,568,957)OPERATING EXPENSES . . . . . . . . . . . . . . . . . . . . . . . . . . (718,000) (744,574) (3,033,338) (1,908,719)

NET OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . . $ 2,303,679 8,736,561 $31,453,181 $21,006,639

See accompanying notes to schedule of revenues, royalties and operating expenses.

FS-42


Notes to Schedule of Revenue, Royalties and Operating ExpensesFor the year ended December 31, 2008

(Information for the three month periods ended March 31, 2009 and 2008 and the year endedDecember 31, 2007 is unaudited)

1. BASIS OF PRESENTATION

This schedule has been prepared by management of Vendor and relates only to the working interests in theproperties transferred from Vendor which closed April 30, 2009.

2. SIGNIFICANT ACCOUNTING PRINCIPLES

(a) Revenues

Revenues from the sale of crude oil, natural gas and natural gas liquids are recorded when title to the commoditiespasses to the purchaser, at the pipeline delivery point for gas and at the wellhead for crude oil. Revenues do not includeany amounts from risk management or other hedging contracts.

(b) Royalties

Royalties are recorded at the time the product is produced and are calculated in accordance with the applicableregulations.

(c) Operating expenses

Operating expenses include all costs related to the lifting, gathering and processing, and delivery to a sales pointof the commodities.

FS-43

October 5, 2009

Auditors’ Report

To the Directors of EnCana Corporation

We have audited the Schedule of Revenues, Royalties and Operating Expenses for the years ended December 31,2008, and 2007 for the Wild River, Harley, Olsen and Sundance Properties. This financial information is theresponsibility of management. Our responsibility is to express an opinion on this financial information based on ouraudits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standardsrequire that we plan and perform an audit to obtain reasonable assurance whether the financial information is free ofmaterial misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosuresin the financial information. An audit also includes assessing the accounting principles used and significant estimatesmade by management, as well as evaluating the overall financial information presentation.

In our opinion, the Schedule of Revenues, Royalties and Operating Expenses presents fairly, in all materialrespects, the revenues, royalties and operating expenses for the Wild River, Harley, Olsen and Sundance Properties forthe years ended December 31, 2008, and 2007 in accordance with Canadian generally accepted accounting principles.


Calgary, AlbertaCanada

FS-44

Wild River, Harley, Olsen and Sundance Properties

Schedule of Revenue, Royalties and Operating Expenses($ thousands)

Six Months EndedJune 30

Year EndedDecember 31

2009(unaudited)

2008(unaudited) 2008 2007

REVENUES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $13,753 32,525 $ 60,338 $ 45,706ROYALTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,065) (3,220) (6,282) (4,429)

12,688 29,305 54,056 41,277OPERATING EXPENSES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,527) (6,439) (11,473) (10,162)

NET OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 8,161 $22,866 $ 42,583 $ 31,115

See accompanying notes to schedule of revenues, royalties and operating expenses.

FS-45


Notes to Schedule of Revenues, Royalties and Operating ExpensesFor the years ended December 31, 2008 and 2007

(Information for the six months ended June 30, 2009 and 2008 is unaudited)


The Schedule of Revenues, Royalties and Operating Expenses includes the operating results relating to the WildRiver, Harley, Olsen and Sundance Properties (“the Property”). The results have been compiled on an activity monthbasis for revenues, royalties and operating expenses.

The Schedule of Revenues, Royalties and Operating Expenses for the Property does not include any provision forthe depletion, depreciation and amortization, asset retirement costs, future capital costs, impairment of unevaluatedproperties, administrative costs and income taxes for the Property as these amounts are based on the consolidatedoperations of the vendor of which the Property forms only a part.


(a) Joint Venture Operations

Substantially all of the Property is operated through joint ventures therefore the schedule reflects only thevendor’s proportionate interest.

(b) Revenue Recognition

Gas revenues are recorded based on Alberta Energy Company reference pricing used for sales between operatingdivisions of EnCana Corporation and do not reflect ultimate marketing related activities. Oil revenues are recordedbased on blended prices established between operating divisions of EnCana Corporation for similar quality productdelivered to a common carrier.

(c) Royalties

Royalties are recorded at the time the product is produced and sold. Royalties are calculated in accordance withthe applicable regulations and/or the terms of individual royalty agreements. Crown royalties for natural gas are basedon the Alberta Government posted reference prices. Crown royalties for crude oil are taken in kind by the AlbertaPetroleum Marketing Commission.

(d) Operating Expenses

Operating Expenses include amounts incurred on extraction of product to the surface, gathering, field processing,treating, field storage and transportation.

FS-46


Balance SheetAs at June 30, 2009 and December 31, 2008

(unaudited)

June 302009

December 312008

$ $

AssetsCurrent assetsCash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 463,075 630,262Term deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,199,767 7,492,650Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,914,855 1,809,385Deposits and prepaid expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 224,988 206,813

7,802,685 10,139,110Property, plant and equipment (note 3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33,641,151 34,480,214Future income tax asset (note 5) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 284,525 —

41,728,361 44,619,324

LiabilitiesCurrent liabilitiesAccounts payable and accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 921,199 2,529,207Asset retirement obligation (note 9) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 347,453 336,609Future income tax liability (note 5) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 169,733

1,268,652 3,035,549

Shareholders’ EquityShare capital (note 4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42,883,129 42,883,129Contributed surplus (note 4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 442,200 435,000Deficit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,865,620) (1,734,354)

40,459,709 41,583,775

41,728,361 44,619,324

See accompanying notes to financial statements.

FS-47


Statement of Operations and DeficitFor the Periods Ended June 30

(unaudited)

June 302009

(3 months)

June 302008

(3 months)

June 302009

(6 months)

June 302008

(6 months)

$ $ $ $

RevenuePetroleum and natural gas sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . 736,192 1,828,899 1,604,315 2,870,902Royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (126,803) (256,457) (181,222) (432,147)Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,117 18,300 8,233 44,365

610,506 1,590,742 1,431,326 2,483,120

ExpensesDepletion, depreciation and amortization . . . . . . . . . . . . . . . . . . . . 933,981 554,740 1,747,958 964,525General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 225,394 487,975 506,431 793,153Operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 391,502 399,358 735,525 713,531Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,291 18,365 26,936 37,241

1,554,168 1,460,438 3,016,850 2,508,450

(Loss) / gain before income taxes . . . . . . . . . . . . . . . . . . . . . . . . . (943,662) 130,304 (1,585,524) (25,330)Future tax (recovery) / expense (note 5) . . . . . . . . . . . . . . . . . . . . . (267,503) 4,272 (454,258) (41,055)

Net (loss) / gain for the period . . . . . . . . . . . . . . . . . . . . . . . . . . . (676,159) 126,032 (1,131,266) 15,725Deficit – Beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,189,461) (1,456,099) (1,734,354) (1,345,792)

Deficit – End of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,865,620) (1,330,067) (2,865,620) (1,330,067)

Net (loss) / gain per share (note 4)Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (0.02) — (0.03) —Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (0.02) — (0.03) —


FS-48


Statement of Cash FlowsFor the Periods Ended June 30

(unaudited)

June 302009

(3 months)

June 302008

(3 months)

June 302009

(6 months)

June 302008

(6 months)

$ $ $ $

Cash provided by (used in)Operating activitiesNet (loss) / gain for the period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (676,159) 126,032 (1,131,266) 15,725Items not affecting cash

Depletion, depreciation and amortization . . . . . . . . . . . . . . . . . . . 933,981 554,740 1,747,958 964,525Stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,600 12,000 7,200 24,000Future income tax (recovery) / expense . . . . . . . . . . . . . . . . . . . . . (267,503) 4,272 (454,258) (41,055)

Cash flow from operations before changes in non-cash workingcapital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6,081) 697,044 169,634 963,195

Changes in non-cash working capitalTerm deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 799,633 (7,639,756) 2,292,883 (2,602,389)Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 452,407 785,621 (105,470) (474,566)Deposits and prepaid expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,376 (5,115) (18,175) (294)Accounts payable and accrued liabilities . . . . . . . . . . . . . . . . . . . . (705,933) (618,424) (1,608,008) (2,994,113)

555,402 (6,780,630) 730,864 (5,108,167)

Investing activitiesAdditions to property, plant and equipment . . . . . . . . . . . . . . . . . . . . (300,482) (147,156) (1,043,551) (1,105,969)Proceeds from asset dispositions . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 5,677,000 145,500 6,002,000

(300,482) 5,529,844 (898,051) 4,896,031

Increase / (decrease) in cash for the period . . . . . . . . . . . . . . . . . . 254,920 (1,250,786) (167,187) (212,136)Cash – Beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 208,155 1,501,882 630,262 463,232

Cash – End of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 463,075 251,096 463,075 251,096


FS-49

1 Nature of operations

Pienza Petroleum Inc. (“Pienza” or the “Corporation”) was incorporated under the laws of Alberta onNovember 21, 2003. Pienza is engaged in the exploration for, and the development and production of petroleum andnatural gas primarily in the Peace River Arch area.

2 Future accounting pronouncements

The CICA confirmed that accounting standards in Canada will converge with International Financial ReportingStandards (“IFRS”). The Corporation will begin reporting under IFRS in 2011, with comparative data for the prioryear. IFRS uses a conceptual framework similar to Canadian generally accepted accounting principals, but there couldbe significant differences in recognition, measurement and disclosures that will need to be addressed.

3 Property, plant and equipment

June 302009

December 312008

$ $

Petroleum and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33,582,763 33,475,549Lease and well equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,141,047 5,350,030Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90,303 90,483

39,814,113 38,916,062Accumulated depletion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6,087,103) (4,353,706)Accumulated depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (85,859) (82,142)

33,641,151 34,480,214

Costs totalling $7,274,368 as at June 30, 2009 (December 31, 2008 – $7,281,218) associated with unprovenproperties have been excluded from the depletion calculation.

For the three and six month periods ended June 30, 2009, the Corporation capitalized $31,851 and $76,841respectively (three and six month periods ended June 30, 2008 – $58,128 and $116,257) of general and administrativecosts associated with exploration and development activities.

4 Share capital and contributed surplus

June 302009

December 312008

$ $

Common shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45,862,832 45,862,832Tax effect of flow-through shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,584,685) (1,584,685)Share issue costs net of tax of $702,720 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,395,018) (1,395,018)

42,883,129 42,883,129

Authorized

The Corporation is authorized to issue an unlimited number of Common shares and an unlimited number ofSpecial Voting shares.

Issued and outstanding

June 302009

December 312008

Number ofshares Amount $

Number ofShares Amount $

Common shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43,017,829 42,883,129 43,017,829 42,883,129

FS-50

Equalization warrants

Holders of all Common shares purchased at $1.00 per share have been granted an Equalization Warrant for eachCommon share owned entitling them to acquire 0.177 Common shares for nominal consideration in the event theproceeds of a Liquidity Event are less than $1.25 per Common share.

As at June 30, 2009 there were 33,481,500 (December 31, 2008 – 33,481,500) exercisable Equalization Warrantsoutstanding.

Performance warrants

The Corporation has authorized Performance Warrants totalling 10.5% of the initial offering of Common andSpecial Voting shares for officers, directors, employees and consultants. Exercise prices range from $1.25 per commonshare to $2.25 per common share, with an average exercise price of $1.75 per common share. The PerformanceWarrants vest over a five year period and expire five years from the date of grant.

As at June 30, 2009 there were 3,390,000 (December 31, 2008 – 3,390,000) Performance Warrants authorized andoutstanding, of which 2,712,000 (December 31, 2008 – 2,542,000) have vested.

Share option plan

The Corporation has authorized 10% of the aggregate number of outstanding Common and Special Voting sharespursuant to an approved share option plan for officers, directors, employees and consultants. As at June 30, 2009 thetotal number of share options granted was 4,230,000 (December 31, 2008 – 4,230,000). Options vest over a three yearperiod and expire five years from the date of grant.

Stock-based compensation costs of $442,200 (December 31, 2008 – $435,000) were reported in contributedsurplus at June 30, 2009 and no stock options were issued in last two years.

A summary of the Corporation’s share option plan is presented below:

June 302009

December 312008

Shares

Weighted-average

exercise price Shares

Weighted-average

exercise price

Outstanding – Beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . 4,230,000 1.08 4,300,000 1.08Cancelled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — (70,000) 1.00

Outstanding – End of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,230,000 1.08 4,230,000 1.08

Options exercisable – End of period . . . . . . . . . . . . . . . . . . . . . . . . 3,940,000 1.06 3,940,000 1.06

Outstanding options are exercisable at a weighted-average price of $1.08 and have an average remainingcontractual life of 0.9 years.

Per share amounts

Net loss per share has been calculated based on the weighted average number of Common shares outstanding of43,017,829 for all reported periods. The reported loss per share of ($0.02) and ($0.03) for the three and six monthperiods ended June 30, 2009 (three and six month periods ended June 30, 2008 – $nil and $nil) is the same for dilutedas it is for basic.

FS-51

5 Income taxes

a) The provisions for future income taxes differs from the results which would be obtained by applying theexpected statutory income tax rate to earnings before taxes as follows:

June 302009

(6 months)

June 302008

(6 months)

$ $

Statutory income tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30.00% 31.30%Expected provision for income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (475,657) (7,928)Effect on income tax of

Stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,160 7,512Change in corporate tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,379 9,619Reclassification of asset disposition costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — (44,446)Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,860 (5,812)

Provision for income taxes recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (454,258) (41,055)

b) The future income tax liability is composed of temporary differences and future income tax reductions. Thesetax-affected differences are as follows:

June 302009

December 312008

$ $

Net book value of tax basis in excess of capital assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,703,493 2,907,425Share issue costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (104,349) (168,729)Asset retirement obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (86,863) (84,152)Loss carry-forward . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,796,806) (2,484,811)

Future income tax (asset) / liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (284,525) 169,733

c) At June 30 the following deductions were available to claim against future taxable income:

June 302009

December 312008

$ $

Canadian exploration expense (CEE) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,159,857 15,084,019Canadian development expense (CDE) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,330,830 2,589,957Canadian oil and gas property expense (COGPE) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,592,377 2,877,638Undepreciated capital costs (UCC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,626,519 3,291,574Non-capital loss carry forward . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,452,809 8,398,311Share issue costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 352,658 560,708

Total tax pools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33,515,050 32,802,207

The non-capital loss carry forward of $9,452,809 expires between 2010 and 2029.

6 Lease obligation and commitments

The Corporation is committed to operating leases with respect to office space up to the period ending April 29,2010. An approximation of the monetary amount of the commitment totals $51,950 due over the next twelve months.

On October 31, 2006, the Corporation entered into a firm transportation and processing agreement with SpectraEnergy Midstream for raw gas production from the Sunrise field. Spectra committed to construct a raw gas flowline toconnect our Sunrise field to a plant which was constructed by Spectra at West Doe in British Columbia. Pienza andpartners have committed a firm volume of 4.25 mmscf/d (Pienza’s share 2.1 mmscf/d) for a three year term, whichcommenced February 2008. The total committed gas production is 4.66 bcf (Pienza’s share 2.3 bcf). The financialcommitment for the three year period is $2,645,000 for transportation and processing costs, net to Pienza.

FS-52

7 Capital disclosures

The Corporation includes cash, term deposits and shareholders’ equity in the definition of capital. TheCorporation’s objectives when managing its capital structure are to maintain sufficient cash and cash equivalents tocover its current operating and administrative budgets and to finance required capital expenditures.

In managing capital, the Corporation estimates its future cash requirements by preparing a budget annually forreview and approval by the Corporation’s Board of Directors (the “Board”). The budget establishes the approvedactivities for the upcoming year and estimates the costs associated with these activities. The forecast estimates futureactivity along with the potential cash requirements. Financial statements reflecting actual activities are preparedquarterly for review and approval by the Board.

8 Financial instruments and risk management

The Corporation’s financial assets and liabilities are comprised of cash, term deposits, accounts receivable,accounts payable and accrued liabilities.

a) The fair values of these financial instruments approximate their carrying amounts due to the short-term maturityof these instruments.

b) The Corporation is exposed to financial risks arising from its financial assets and liabilities. Financial risksinclude market risk (commodity prices), credit risk and liquidity risk. The fair value or future cash flows of financialassets or liabilities may fluctuate due to movement in market prices and the exposure to credit and liquidity risks.

Commodity price risk

Commodity price risk arises from the effect that fluctuations of future commodity prices may have on the fairvalue or future cash flows of financial assets and liabilities. The Corporation manages the commodity price uncertaintypartly by possessing both oil and gas production. Estimation of future cash flows are amended quarterly to include boththe most current and forecast pricing.

Credit risk

Credit risk arises from the potential the Corporation may incur a loss if a counterparty to a financial instrumentfails to meet its obligation in accordance with agreed terms. The Corporation is exposed to credit risk on its cash, termdeposits and accounts receivable.

The Corporation mitigates its exposure to credit risk on cash and term deposits by maintaining its bank accountswith a Canadian Chartered bank and all term deposits are restricted by the Board to be in the form of short-termbankers’ acceptances. The vast majority of the Corporation’s accounts receivable are with customers in the oil and gasindustry and are subject to normal industry credit risks. The maximum credit risk exposure associated with cash, termdeposits and accounts receivable is the total carrying value.

Liquidity risk

Liquidity risk is the risk the Corporation will encounter difficulties in meeting a demand to fund its financialliabilities as they come due. The Corporation manages its liquidity risk by keeping surplus cash in highly liquidsecurities of highly-rated financial institutions. This allows the Corporation to earn modest interest rates on surpluscash while also having access to it in a very short time frame.

9 Asset retirement obligation

The Corporation’s asset retirement obligation is based on the Corporation’s net ownership in wells and facilitiesand management’s estimate of the costs to abandon and reclaim those wells and facilities as well as an estimate of thefuture timing of the costs to be incurred.

FS-53

The total undiscounted amount of future cash flows required to settle asset retirement obligations is estimated tobe $706,752 (December 31, 2008 – $706,752). Payments to settle asset retirement obligations occur over the operatinglives of the assets estimated to be from 1 to 14 years. Estimated cash flows have been discounted at the Corporation’scredit-adjusted risk free rate of 8 percent and an inflation rate of 2 percent.

June 302009

December 312008

$ $

Carrying amount – Beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 336,609 475,581Liabilities incurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 22,118Liabilities reduced . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — (184,953)Accretion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,844 23,863

Carrying amount – End of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 347,453 336,609

10 Supplementary cash flow information

In the period ended June 30, 2009 actual cash interest received by the Corporation for the three and six monthperiods ended June 30, 2009 totalled $1,022 and $13,367 respectively (three and six month periods ended June 30,2008 – $18,300 and $54,525) and no cash taxes were paid by the Corporation in any of the reported periods.

11 Subsequent events

Effective September 15, 2009, the Corporation was acquired by Tourmaline Oil Corp. in a combination share andcash arrangement. Prior to the acquisition, and in anticipation thereof, 3,259,996 share options were exercised byofficers, directors, employees and consultants. The acquisition also triggered the exercising of 33,481,500 equalizationwarrants resulting in the issuance of 5,926,225 additional shares. Effective purchase price was $0.93 per Pienza share.

FS-54

PricewaterhouseCoopers LLP 111 5 Avenue SW, Suite 3100 Calgary, Alberta Canada T2P 5L3 Telephone +1 403 509 7500 Facsimile +1 403 781 1825

May 4, 2009

Auditors’ Report

To the Shareholders ofPienza Petroleum Inc.

We have audited the balance sheets of Pienza Petroleum Inc. as at December 31, 2008 and 2007, the statement ofoperations and deficit and the statement of cash flows for the years then ended. These financial statements are theresponsibility of the Company’s management.

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted ouraudits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan andperform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. Anaudit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.An audit also includes assessing the accounting principles used and significant estimates made by management, as wellas evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial positionof the Company as at December 31, 2008 and 2007 and the results of its operations and its cash flows for the years thenended in accordance with Canadian generally accepted accounting principles.

Chartered AccountantsCalgary, Alberta

“PricewaterhouseCoopers” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership, or, as the context requires, thePricewaterhouseCoopers global network or other member firms of the network, each of which is a separate and independent legal entity.

FS-55


Balance SheetAs at December 31

2008 2007

$ $

AssetsCurrent assetsCash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 630,262 463,232Term deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,492,650 5,037,367Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,809,385 1,584,839Deposits and prepaid expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 206,813 205,755

10,139,110 7,291,193Property, plant and equipment (note 3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34,480,214 39,361,909

44,619,324 46,653,102

LiabilitiesCurrent liabilitiesAccounts payable and accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,529,207 3,833,307Asset retirement obligation (note 9) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 336,609 475,581Future income tax liability (note 5) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 169,733 416,877

3,035,549 4,725,765

Shareholders’ EquityShare capital (note 4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42,883,129 42,883,129Contributed surplus (note 4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 435,000 390,000Deficit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,734,354) (1,345,792)

41,583,775 41,927,337

44,619,324 46,653,102

Approved by the Board of Directors

Director Director


FS-56


Statement of Operations and DeficitFor the Years Ended December 31

2008 2007

$ $

RevenuePetroleum and natural gas sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,364,310 1,842,063Royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,076,649) (117,060)Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 155,956 227,222

4,443,617 1,952,225

ExpensesDepletion, depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,287,785 1,074,110General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,327,880 997,449Operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,390,741 480,916Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70,766 73,724

5,077,172 2,626,199

Loss before income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (633,555) (673,974)

Income taxes (note 5)Current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,151 —Future tax recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (247,144) (222,114)

(244,993) (222,114)

Net loss for the year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (388,562) (451,860)Deficit – Beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,345,792) (893,932)

Deficit – End of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,734,354) (1,345,792)

Net loss per share (note 4)Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (0.01) (0.01)Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (0.01) (0.01)


FS-57


Statement of Cash FlowsFor the Years Ended December 31

2008 2007

$ $

Cash provided by (used in)Operating activitiesNet loss for the year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (388,562) (451,860)Items not affecting cash

Depletion, depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,287,785 1,074,110Stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45,000 129,000Future income tax recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (247,144) (222,114)

Cash flow from operations before changes in non-cash working capital . . . . . . . . . . . . . . . . . 1,697,079 529,136

Changes in non-cash working capitalTerm deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,455,283) 1,944,453Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (224,546) 408,603Deposits and prepaid expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,058) 17,708Accounts payable and accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,304,100) 2,098,635

(2,287,908) 4,998,535

Investing activitiesAdditions to property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,693,972) (5,388,840)Proceeds from asset dispositions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,148,910 —

2,454,938 (5,388,840)

Increase / (decrease) in cash for the year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 167,030 (390,305)Cash – Beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 463,232 853,537

Cash – End of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 630,262 463,232


FS-58


Notes to Financial StatementsFor the Years Ended December 31, 2008 and 2007

1 Nature of operations

Pienza Petroleum Inc. (“Pienza” or the “Corporation”) was incorporated under the laws of Alberta onNovember 21, 2003. Pienza is engaged in the exploration for, and the development and production of petroleum andnatural gas primarily in the Peace River Arch area.

2 Significant accounting policies

Basis of presentation

These financial statements have been prepared in accordance with generally accepted accounting principles inCanada as outlined below.

Cash and cash equivalents

Cash and cash equivalents are comprised of cash and short-term investments with an initial maturity date of threemonths or less.

Property, plant and equipment

a) Capitalized costs

The Corporation follows the full cost method of accounting for petroleum and natural gas properties whereby allcosts related to the acquisition, exploration and development of oil and gas reserves are capitalized. Costs include leaseacquisition, lease maintenance on non-productive lands, geological and geophysical costs, drilling expenditures, plantand production equipment costs and related overhead costs. Proceeds on disposal of properties are deducted fromcapitalized costs without recognition of gain or loss except for dispositions which would alter the depletion rate by20% or more.

b) Depletion and depreciation

Capital costs, including estimated costs of developing proved reserves, are depleted on the unit-of-productionmethod based on estimated gross proven reserves. Gas volumes are converted to equivalent energy units of oil on thebasis of six thousand cubic feet of gas to one barrel of oil. The cost of unproven properties is excluded from thedepletion base. The unproven properties are assessed periodically to ascertain whether impairment has occurred. Whenproved reserves are assigned or the value of the unproven property is considered to be impaired, the cost of theunproven property or the amount of the impairment is added to the cost subject to depletion.

Depreciation of other assets is calculated on a straight line basis taking the estimated useful asset lives and salvagevalues into consideration.

c) Ceiling test

In applying the full-cost method, the Corporation performs a ceiling test to compare the carrying amount of theassets to its fair value. The recoverability of an asset is tested by comparing the carrying value of the asset to the sumof the undiscounted cash flows expected from the asset’s use and eventual disposition. If the carrying value isunrecoverable, the asset is written down to its fair value using the expected present value approach. This approachincorporates risks and uncertainties in the expected cash flows, which are discounted using a risk free rate.

Use of estimates

The amounts recorded for depletion and depreciation and asset retirement obligation are based on estimates. Theceiling test calculation is based on such factors as estimates of proved reserves, production rates, product prices andfuture costs. By their nature, these estimates are subject to measurement uncertainty and may impact the financialstatements of future periods.

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Flow-through shares

The Corporation issues flow-through shares and the resultant proceeds are used to fund exploration expenditureswithin a defined time period. The income tax deductions associated with the expenditures funded by flow-througharrangements are renounced to investors in accordance with the appropriate tax legislation. A future tax liability isrecognized and share capital is reduced by the estimated cost of the renounced tax deductions when the expendituresare renounced.

Joint venture operations

Substantially all of the Corporation’s exploration and production activities are conducted jointly with otherentities and accordingly, the accounts reflect only the Corporation’s proportionate interest in such activities.

Stock-based compensation plan

The Corporation has a stock option plan enabling officers, directors and certain employees and consultants topurchase common shares at exercise prices equal to the market price on the date the option is granted. The Corporationhas adopted the fair value method for accounting for stock-based compensation. Compensation costs are estimated andcharged to earnings over the vesting period of the underlying security.

Revenue recognition

Revenues from petroleum and natural gas sales are recorded when title passes from the Corporation to itscustomers.

Asset retirement obligations

The Corporation estimates asset retirement obligation based on the estimated costs to abandon and reclaim its netownership interest in all wells and facilities and the estimated timing of the costs to be incurred in future periods. Theliability for future retirement obligations is recorded in the financial statements at the time the liability is incurred, witha corresponding increase to the carrying amount of the related asset.

Earnings per share

Earnings per share is calculated based on the weighted average number of Common shares outstanding during theyear. Diluted earnings per share reflects the exercise of options and performance warrants, as if issued at the later of thedate of grant or the beginning of the year. Under the treasury stock method, only “in the money” options and warrantsare included in the weighted average number of shares. It is assumed that the proceeds from the exercise of options andwarrants are used to buy back shares at the calculated net asset value at the end of the reporting period. The weightedaverage number of shares is then increased by the number of incremental shares issued.

Changes in accounting policies and practices

On January 1, 2008, the Corporation adopted the following CICA Handbook Sections:

Section 1535 – Capital Disclosures. The new standard requires the Corporation to disclose its objectives, policiesand processes for managing its capital structure (see Note 7).

Section 3862 – Financial Instruments – Disclosures and Section 3863 – Financial Instruments – Presentation. Thenew disclosure standard increases the Corporation’s disclosure regarding the nature and extent of the risks associatedwith financial instruments and how those risks are managed (see Note 8). The new presentation standard carriesforward the former presentation requirements.

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Future accounting pronouncements

The CICA confirmed that accounting standards in Canada will converge with International Financial ReportingStandards (“IFRS”). The Corporation will begin reporting under IFRS in 2011, with comparative data for the prioryear. IFRS uses a conceptual framework similar to Canadian generally accepted accounting principals, but there couldbe significant differences in recognition, measurement and disclosures that will need to be addressed.

3 Property, plant and equipment

2008 2007

$ $

Petroleum and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33,475,549 36,318,148Lease and well equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,350,030 5,125,205Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90,483 90,483

38,916,062 41,533,836Accumulated depletion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,353,706) (2,100,685)Accumulated depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (82,142) (71,242)

34,480,214 39,361,909

Costs totalling $7,281,218 (2007 – $8,410,088) associated with unproven properties have been excluded from thedepletion calculation.

The Corporation capitalized $232,514 (2007 – $315,985) of general and administrative costs associated withexploration and development activities.

The Corporation performed a ceiling test as at December 31, 2008 and no impairment was recorded. Thefollowing table outlines prices used in the ceiling test:

YearOil

($Cdn/BBL)

Gas($Cdn/

MMBTU)

2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66.61 8.322010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76.94 8.682011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81.54 9.172012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88.92 9.532013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 9.782014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 10.042015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 10.232016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 10.45

4 Share capital and contributed surplus

2008 2007

$ $

Common shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45,862,832 45,862,832Tax effect of flow-through shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,584,685) (1,584,685)Share issue costs net of tax of $702,720 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,395,018) (1,395,018)

42,883,129 42,883,129

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Authorized

The Corporation is authorized to issue an unlimited number of Common shares and an unlimited number ofSpecial Voting shares.


2008 2007

Number ofshares Amount

Number ofshares Amount

$ $

Common sharesBeginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43,017,829 42,883,129 43,017,829 43,671,261Tax effect of flow-through shares . . . . . . . . . . . . . . . . . . . . . . . . . — — — (788,132)

Total Common shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43,017,829 42,883,129 43,017,829 42,883,129

Equalization warrants

Holders of all Common shares purchased at $1.00 per share have been granted an Equalization Warrant for eachCommon share owned entitling them to acquire 0.177 Common shares for nominal consideration in the event theproceeds of a Liquidity Event are less than $1.25 per Common share.

As at December 31, 2008 there were 33,481,500 (2007 – 33,481,500) exercisable Equalization Warrantsoutstanding.

Performance warrants

The Corporation has authorized Performance Warrants totalling 10.5% of the initial offering of Common andSpecial Voting shares for officers, directors, employees and consultants. Exercise prices range from $1.25 per commonshare to $2.25 per common share, with an average exercise price of $1.75 per common share. The PerformanceWarrants vest over a five year period and expire five years from the date of grant.

As at December 31, 2008 there were 3,390,000 (2007 – 3,465,000) Performance Warrants authorized andoutstanding, of which 2,542,000 (2007 – 1,884,000) have vested.

Share option plan

The Corporation has authorized 10% of the aggregate number of outstanding Common and Special Voting sharespursuant to an approved share option plan for officers, directors, employees and consultants. As at December 31, 2008the total number of share options granted was 4,230,000 (2007 – 4,300,000). Options vest over a three year period andexpire five years from the date of grant.

Stock-based compensation costs of $435,000 (2007 – $390,000) were reported in contributed surplus in 2008 andno stock options were issued in last two years.

FS-62



A summary of the Corporation’s share option plan is presented below:

2008 2007

SharesWeighted- average

exercise price SharesWeighted- average

exercise price

Outstanding – Beginning of year . . . . . . . . . . . . . . . . . . . . 4,300,000 1.08 4,300,000 1.08Cancelled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (70,000) 1.00 — —

Outstanding – End of year . . . . . . . . . . . . . . . . . . . . . . . . . 4,230,000 1.08 4,300,000 1.08

Options exercisable – End of year . . . . . . . . . . . . . . . . . . . 3,940,000 1.06 3,430,000 1.03

Outstanding options are exercisable at a weighted-average price of $1.08 and have an average remainingcontractual life of 1.39 years.

Per share amounts

Loss per share has been calculated based on the weighted average number of Common shares outstanding of43,017,829 (2007 – 43,017,829). The reported loss per share of ($0.01) (2007 – ($0.01)) is the same for diluted as it isfor basic.

5 Income taxes

a) The provisions for future income taxes differs from the results which would be obtained by applying theexpected statutory income tax rate to earnings before taxes as follows:

2008 2007

$ $

Statutory income tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30.76% 32.30%Expected provision for income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (194,907) (217,660)Effect on income tax of Stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13,844 41,661

Effect of change in corporate tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (88,242) (34,064)Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22,161 (12,051)

Provision for income taxes recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (247,144) (222,114)

b) The future income tax liability is composed of temporary differences and future income tax reductions. Thesetax-affected differences are as follows:

2008 2007

$ $

Net book value of tax basis in excess of capital assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,907,425 3,074,059Share issue costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (168,729) (303,731)Asset retirement obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (84,152) (128,205)Loss carry-forward . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,484,811) (2,225,246)

Future income tax liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 169,733 416,877

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c) At December 31 the following deductions were available to claim against future taxable income:

2008 2007

$ $

Canadian exploration expense (CEE) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,084,019 14,416,773Canadian development expense (CDE) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,589,957 4,113,117Canadian oil and gas property expense (COGPE) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,877,638 6,753,084Undepreciated capital costs (UCC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,291,574 3,534,839Non-capital loss carry forward . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,398,311 7,177,618Share issue costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 560,708 981,190

Total tax pools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32,802,207 36,976,621

The non-capital loss carry forward of $8,398,311 expires between 2010 and 2028.

6 Lease obligation and commitments

The Corporation is committed to operating leases with respect to office space up to the period ending May 30,2009. An approximation of the monetary amount of the commitment totals $55,364 due in 2009 (includes basic rentand the Corporation’s share of operating costs).

On October 31, 2006, the Corporation entered into a firm transportation and processing agreement with SpectraEnergy Midstream for raw gas production from the Sunrise field. Spectra committed to construct a raw gas flowline toconnect our Sunrise field to a plant which was constructed by Spectra at West Doe in British Columbia. Pienza andpartners have committed a firm volume of 4.25 mmscf/d (Pienza’s share 2.1 mmscf/d) for a three year term, whichcommenced February 2008. The total committed gas production is 4.66 bcf (Pienza’s share 2.3 bcf). The financialcommitment for the three year period is $2,645,000 for transportation and processing costs, net to Pienza.

7 Capital disclosures

The Corporation includes cash, term deposits and shareholders’ equity in the definition of capital. TheCorporation’s objectives when managing its capital structure are to maintain sufficient cash and cash equivalents tocover its current operating and administrative budgets and to finance required capital expenditures.

In managing capital, the Corporation estimates its future cash requirements by preparing a budget annually forreview and approval by the Corporation’s Board of Directors (the “Board”). The budget establishes the approvedactivities for the upcoming year and estimates the costs associated with these activities. The forecast estimates futureactivity along with the potential cash requirements. Financial statements reflecting actual activities are preparedquarterly for review and approval by the Board.

8 Financial instruments and risk management

The Corporation’s financial assets and liabilities are comprised of cash, term deposits, accounts receivable,accounts payable and accrued liabilities.

a) The fair values of these financial instruments approximate their carrying amounts due to the short-term maturityof these instruments.

b) The Corporation is exposed to financial risks arising from its financial assets and liabilities. Financial risksinclude market risk (commodity prices), credit risk and liquidity risk. The fair value or future cash flows of financialassets or liabilities may fluctuate due to movement in market prices and the exposure to credit and liquidity risks.

FS-64



Commodity price risk

Commodity price risk arises from the effect that fluctuations of future commodity prices may have on the fairvalue or future cash flows of financial assets and liabilities. The Corporation manages the commodity price uncertaintypartly by possessing both oil and gas production. Estimation of future cash flows are amended quarterly to include boththe most current and forecast pricing.

Credit risk

Credit risk arises from the potential the Corporation may incur a loss if a counterparty to a financial instrumentfails to meet its obligation in accordance with agreed terms. The Corporation is exposed to credit risk on its cash, termdeposits and accounts receivable.

The Corporation mitigates its exposure to credit risk on cash and term deposits by maintaining its bank accountswith a Canadian Chartered bank and all term deposits are restricted by the Board to be in the form of short-termbankers’ acceptances. The vast majority of the Corporation’s accounts receivable are with customers in the oil and gasindustry and are subject to normal industry credit risks. The maximum credit risk exposure associated with cash, termdeposits and accounts receivable is the total carrying value.

Liquidity risk

Liquidity risk is the risk the Corporation will encounter difficulties in meeting a demand to fund its financialliabilities as they come due. The Corporation manages its liquidity risk by keeping surplus cash in highly liquidsecurities of highly-rated financial institutions. This allows the Corporation to earn modest interest rates on surpluscash while also having access to it in a very short time frame.

9 Asset retirement obligation

The Corporation’s asset retirement obligation is based on the Corporation’s net ownership in wells and facilitiesand management’s estimate of the costs to abandon and reclaim those wells and facilities as well as an estimate of thefuture timing of the costs to be incurred.

The total undiscounted amount of future cash flows required to settle asset retirement obligations is estimated tobe $706,752 (2007 – $978,200). Payments to settle asset retirement obligations occur over the operating lives of theassets estimated to be from 1 to 14 years. Estimated cash flows have been discounted at the Corporation’s credit-adjusted risk free rate of 8 percent and an inflation rate of 2 percent.

2008 2007

$ $

Carrying amount – Beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 475,581 398,994Liabilities incurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22,118 54,866Liabilities reduced . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (184,953) —Accretion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23,863 21,721

Carrying amount – End of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 336,609 475,581

10 Supplementary cash flow information

Actual cash interest received by the Corporation in 2008 totalled $161,179 (2007 – $230,309) and cash taxes paidby the corporation in 2008 totalled $26,846 (2007 – nil).

FS-65

VIGILANT EXPLORATION INC.

Balance SheetsAs At

September 302009

June 302009

$ $(unaudited) (audited)

ASSETSCURRENT

Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,423,716 9,598,934Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,118,241 1,183,734Prepaid expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 15,272Marketable securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 150,005 —

11,691,962 10,797,940Long-term deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 311,083 311,083Property and equipment (note 3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30,668,406 32,606,968

42,671,451 43,715,991

LIABILITIESCURRENT

Accounts payable and accrued liabilities (note 11) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,435,444 2,008,539Preferred share (note 6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1

2,435,445 2,008,540Asset retirement obligations (note 5) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 867,822 850,639

3,303,267 2,859,179

SHAREHOLDERS’ EQUITYEquity instruments (note 7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66,294,556 65,327,887Contributed surplus (note 8) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,603,124 2,528,574Deficit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (29,529,496) (26,999,649)

39,368,184 40,856,812

42,671,451 43,715,991

Commitments (note 11)Subsequent events (note 14)

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Statements of Operations and DeficitThree Months Ended September 30,

(unaudited)

2009 2008

$ $

REVENUEPetroleum and natural gas sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,063,292 3,251,735Royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (418,708) (766,659)Royalty income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,279 14,613Interest and other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,977 18,014

1,663,840 2,517,703

EXPENSESOperating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 520,895 663,829General and administrative (note 11) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 895,828 711,066Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,560 1,824Depletion, depreciation and accretion (note 3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,161,816 1,453,962Stock-based compensation (note 7[f]) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 611,588 (41,721)

4,193,687 2,788,960

NET LOSS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,529,847) (271,257)DEFICIT, BEGINNING OF PERIOD . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (26,999,649) (23,843,682)

DEFICIT, END OF PERIOD . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (29,529,496) (24,114,939)

Net loss per share – basic and diluted (note 7[g]) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (0.04) $ (0.01)

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Statements of Cash FlowsThree Months Ended September 30,

(unaudited)

2009 2008

$ $

CASH FLOWS RELATED TO THE FOLLOWING ACTIVITIES:OPERATING

Net loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,529,847) (271,257)Adjustments for items not affecting cash:

Depletion, depreciation and accretion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,161,816 1,453,962Stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 611,588 (41,721)

243,557 1,140,984Changes in non-cash working capital (note 10) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 392,032 237,172

635,589 1,378,156

FINANCINGIssuance of shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 429,631 —

—INVESTING

Additions to property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (206,071) (552,514)Changes in non-cash working capital (note 10) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (34,367) 140,028

(240,438) (412,486)

NET INCREASE IN CASH AND CASH EQUIVALENTS . . . . . . . . . . . . . . . . . . . . . . . . . 824,782 965,670CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD . . . . . . . . . . . . . . . . . . . 9,598,934 2,913,262

CASH AND CASH EQUIVALENTS, END OF PERIOD . . . . . . . . . . . . . . . . . . . . . . . . . . 10,423,716 3,878,932

FS-68


Notes to the Financial StatementsSeptember 30, 2009

1. NATURE OF OPERATIONS AND BASIS OF PRESENTATION

Vigilant Exploration Inc. (the “Corporation”) was incorporated under the Canada Business Corporations Act onOctober 14, 2003. The Corporation’s principal business is the acquisition, exploration and development of oil and gasproperties in Western Canada. Pursuant to articles of amalgamation filed effective July 1, 2009, the Corporation and itswholly owned subsidiary 7198621 Canada Inc. (formerly Outrider Energy Ltd.) amalgamated and continued under thename Vigilant Exploration Inc.

These unaudited interim financial statements have been prepared on a basis applicable to a continuing entity inaccordance with Canadian generally accepted accounting principles (“GAAP”), following the same accounting policiesand methods of computation as the audited consolidated financial statements of the Corporation as at June 30, 2009 andfor the year then ended. These unaudited interim financial statements do not include all disclosures required in theannual financial statements and should be read in conjunction with the Corporation’s audited consolidated financialstatements and notes thereto as at June 30, 2009 and for the year then ended.

The successful future operations of the Corporation are dependent on its ability to secure sufficient funds throughfinancings, borrowings and operations to be able to meet the Corporation’s obligations as they become due. As atSeptember 30, 2009, the Corporation had a deficit of $29,529,496 and a working capital surplus, including long-termdeposits, of $9,567,600 and for the three months then ended incurred a net loss of $2,529,847 and generated cash inoperating activities of $635,589. During the year ended June 30, 2009, the Corporation entered into an agreement witha Canadian banking institution to provide an additional source of financing (note 4). Although management believesthe Corporation’s capital structure (note 7[h]) is sufficient as at September 30, 2009, the Corporation’s exploration anddevelopment activities are inherently uncertain and there can be no certainty that sufficient resources will be availableto undertake such activities. The Corporation’s future operations may be altered by the completion of the transaction(note 14[d]) with Tourmaline Oil Corp.


The financial statements of the Corporation have been prepared by management in accordance with Canadiangenerally accepted accounting principles. The preparation of financial statements in conformity with GAAP requiresmanagement to make estimates and assumptions that affect the amounts reported in the financial statements andaccompanying notes. Actual results could differ from those estimates. The financial statements have, in management’sopinion, been properly prepared using careful judgment with reasonable limits of materiality and within the frameworkof the significant policies in the annual consolidated financial statements with the changes noted below.

Changes in accounting policies

As of July 1, 2009, the Corporation adopted Section 1000, Financial Statement Concepts which has been amendedto focus on the capitalization of costs that truly meet the definition of an asset and de-emphasizes the matchingprinciple.

As of July 1, 2009, the Corporation adopted Section 3064, Goodwill and Intangible Assets which establishesstandards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets. In particular,this section restricts the ability of a company to recognize internal costs as deferred assets.

The adoption of these standards did not impact the Corporation’s financial statements.

FS-69



3. PROPERTY AND EQUIPMENT

September 302009

June 302009

$ $CostPetroleum and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80,425,918 80,219,847Office furniture and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 963,105 963,105

81,389,023 81,182,952

Accumulated depletion, depreciation and impairmentPetroleum and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (49,791,723) (47,749,723)Office furniture and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (928,894) (826,261)

(50,720,617) (48,575,984)

30,668,406 32,606,968

Costs related to undeveloped properties of $347,000 (June 30, 2009 – $347,000) have been excluded from thedepletion and depreciation calculation. Future development costs of proved reserves of $4,269,000 (June 30, 2009 –$4,269,000) have been included in the depletion and depreciation calculation. The Corporation does not capitalizedirect general and administrative costs.

4. BANK INDEBTEDNESS

The Corporation has a $6,500,000 (June 30, 2009 – $6,500,000) demand revolving operating loan by way ofcurrent account overdraft with a Canadian banking institution (the “Lender”) that also allows the Corporation theability to issue letters of credit up to an aggregate maximum amount of $1.0 million that reduces the amount availableunder current account overdraft. This credit facility bears interest at prime plus 0.85%, includes a standby fee of 0.20%on the undrawn portion and is secured by a general security agreement.

Borrowings under the credit facility are subject to a maximum amount equal to the Corporation’s borrowing baseas determined by the Lender. The credit facility includes certain financial covenants that the Corporation will not atany time, without the consent of the Lender, breach as follows: (i) permit the working capital ratio of the Corporationto fall below 1.00:1; or (ii) permit the Corporation’s net debt to trailing cash flow to exceed 3.00:1. The Lender definesworking capital ratio as the ratio of (i) current assets plus any undrawn availability under the credit facility to(ii) current liabilities less any amount drawn under the credit facility. The Lender defines net debt as the Corporation’stotal debt less current assets; defines cash flow as the Corporation’s revenue less expenses plus future income taxes,amortization and other non-cash charges; and defines trailing cash flow as the Corporation’s cash flow for the mostrecently completed fiscal quarter, annualized.

As at September 30, 2009 no amount (June 30, 2009 – $nil) was drawn on this facility, except for letters of creditin the amount of $53,000 (June 30, 2009 – $53,000).


September 302009

June 302009

$ $

Balance, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 850,639 348,230Liabilities incurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 47,357Change in estimate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 9,815Accretion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17,183 32,396Acquired on acquisition of Outrider Energy Ltd. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 412,841

Balance, end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 867,822 850,639

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The undiscounted amount of expected cash flows required to settle the asset retirement obligation is estimated at$1,703,995 (June 30, 2009 – $1,712,630). The Corporation expects these obligations to be settled at various times untilapproximately 2052, with the majority of the costs being incurred between 2017 and 2030. The liability for theexpected cash flows, as reflected in the financial statements, has been discounted at credit adjusted risk free rates of6.50% and 9.95%, and an inflation rate of 2.0%. The costs attributable to the future asset retirement obligations areexpected to be funded mainly from the Corporation’s cash provided by operating activities.

6. PREFERRED SHARE

The Corporation has one issued and outstanding preferred share (note 7[a]), which is redeemable and retractable at$1.00 per share plus all declared and unpaid dividends thereon. As this preferred share is retractable at the option of theholder and redeemable at the option of the Corporation, a liability in the amount of $1 has been reflected in theCorporation’s financial statements. Subsequent to September 30, 2009 the Corporation provided a notice of redemptionto the holder of the preferred share that resulted in the Corporation redeeming the preferred share on November 9, 2009at a redemption price equal to $1.

7. EQUITY INSTRUMENTS

a) Authorized

Unlimited number of Common Shares, which have the right to vote, receive dividends and to receive theremaining property of the Corporation on dissolution.

Unlimited number of Special Voting Shares, which have the right to vote and no entitlement to receive dividendsor to receive the remaining property of the Corporation on dissolution.

Unlimited number of Preferred Shares, which are retractable at the option of the holder or redeemable at theoption of the Corporation at a price of $1.00 per share and have no entitlement to receive dividends or to receive theremaining property of the Corporation on dissolution (note 6).

b) Issued and Outstanding

Number ofShares

Amount$

Common SharesBalance, June 30, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43,096,343 47,079,162

Issued for acquisition of Outrider Energy Ltd. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19,000,000 18,168,725

Balance, June 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62,096,343 65,247,887Issued (note 7[c]) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,148,154 966,669

Balance, September 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64,244,497 66,214,556

Broker Warrants (note 7[d])Balance, September 30, 2009 and June 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 779,900 80,000

Equity instruments, September 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66,294,556

Equity instruments, June 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65,327,887

c) Private Placement

Pursuant to a private placement on July 31, 2009 the Corporation issued 2,148,154 Common Shares at $0.20 pershare to certain officers and one director of the Corporation for proceeds of $429,631. The difference between theissuance price of $0.20 per share and the estimated fair value of the Corporation’s Common Shares is $537,038, whichis recorded as stock-based compensation with a corresponding amount being recorded to share capital.

FS-71



d) Broker Warrants

The following table summarizes information about the warrants outstanding as at September 30, 2009:

Description OutstandingWarrant

price

Weightedaverage

remainingcontractuallife (years)

Number ofexercisableat Sept 30,

2009

Weightedaverageexerciseprice

Broker warrants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 217,400 $1.00 note 7[d](i) 217,400 $1.00Broker warrants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 187,500 $1.00 0.36 187,500 $1.00Broker warrants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 187,500 $1.50 0.36 187,500 $1.50Broker warrants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 187,500 $2.00 0.36 187,500 $2.00

779,900 779,900

The following table summarizes information about the warrants outstanding as at June 30, 2009:

Description OutstandingWarrant

price

Weightedaverage


Number ofexercisableat June 30,

2009


Broker warrants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 217,400 $1.00 note 7[d](i) 217,400 $1.00Broker warrants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 187,500 $1.00 0.61 187,500 $1 00Broker warrants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 187,500 $1.50 0.61 187,500 $1.50Broker warrants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 187,500 $2.00 0.61 187,500 $2.00

779,900 779,900

(i) Contractual life is not known at this time, as expiry is set for 12 months after a liquidity event occurs (note 14[c]).

e) Stock Options

The Corporation has an incentive stock option plan pursuant to which the Corporation may issue Common Sharesupon the exercise of stock options that may be granted to directors, officers, employees and consultants. The planallows for stock options to be granted on up to 12% of the total number of Common Shares issued and outstanding.The exercise price, terms of vesting and expiry date of stock options are fixed by the board of directors of theCorporation at the time of grant. All outstanding options vest over a three year period from the date of grant, orotherwise as in accordance with the stock option plan, and expire five years from the date of grant. The maximumnumber of stock options available for grant as at September 30, 2009, is 7,709,339 (June 30, 2009 – 7,451,561) ofwhich 4,485,000 (June 30, 2009 – 1,105,000) have been granted.

On July 31, 2009 the Corporation cancelled the existing 1,105,000 stock options that were outstanding at June 30,2009 and issued 4,485,000 stock options to directors, officers and employees of the Corporation, of which 1,175,000were exercisable at $0.20 per share and 3,310,000 were exercisable at $0.45 per share. All of these 4,485,000 stockoptions expire five years from the date of grant and vest equally over a three year period from the date of grant, exceptthat 308,334 stock options with an exercise price of $0.20 per share and 656,666 stock options with an exercise price of$0.45 per share, or cumulatively 965,000 stock options, vest immediately upon date of grant.

Subsequent to September 30, 2009 the Corporation issued 965,000 Common Shares upon the exercise of 965,000stock options, of which 308,334 had an exercise price of $0.20 per share and 656,666 had an exercise price of $0.45 pershare.

FS-72



Subsequent to September 30, 2009, pursuant to the transaction with Tourmaline Oil Corp. (note 14[d]), theCorporation cancelled 3,520,000 stock options, of which 866,666 had an exercise price of $0.20 per share and2,653,334 had an exercise price of $0.45 per share.

Options Outstanding

Options

Number ofcommonsharesissuable


Balance, June 30, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,371,667 4,371,667 $ 1.16Forfeited July 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (135,000) (135,000) ($1.11)Expired August 29, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (91,667) (91,667) ($1.60)Forfeited October 6, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (240,000) (240,000) ($1.08)Forfeited October 22, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (176,667) (176,667) ($1.08)Expired October 29, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (115,000) (115,000) ($1.07)Forfeited November 4, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (46,667) (46,667) ($1.07)Forfeited November 7, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (166,667) (166,667) ($1.20)Forfeited December 17, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (181,667) (181,667) ($1.29)Expired January 4, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (680,000) (680,000) ($1.06)Expired January 20, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (453,333) (453,333) ($1.06)Expired February 2, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (88,333) (88,333) ($1.08)Expired February 5, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (133,333) (133,333) ($1.50)Expired March 17, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (403,333) (403,333) ($1.16)Forfeited April 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (355,000) (355,000) ($1.08)

Balance, June 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,105,000 1,105,000 $ 1.26Cancelled July 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,105,000) (1,105,000) ($1.26)Issued July 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,485,000 4,485,000 $ 0.38

Balance, September 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,485,000 4,485,000 $ 0.38

The weighted average remaining contractual life and weighted average exercise price of options outstanding andof options exercisable as at September 30, 2009 are as follows:

Options outstanding Option price


contractual life(years)

Number ofoptions currently

exercisable

Weighted averageexercise price ofoptions currently

exercisable

1,175,000 $0.20 4.84 308,334 $0.203,310,000 $0.45 4.84 656,666 $0.45

4,485,000 4.84 965,000 $0.37

The weighted average remaining contractual life and weighted average exercise price of options outstanding andof options exercisable as at June 30, 2009 are as follows:



contractual life(years)

Number ofoptions currently

exercisable


exercisable

625,000 $1,00 2.38 375,000 $1.00480,000 $1.60 2.68 320,000 $1.60

1,105,000 2.51 695,000 $1.28

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f) Stock-based Compensation

During the three months ended September 30, 2009 the Corporation granted stock options to officers, directorsand employees to purchase up to 4,485,000 Common Shares. Upon the issuance of these stock options the Corporationascribed a value of $564,454 using the Black-Scholes option valuation model with a volatility of 10%, risk free rate of2.7%, dividend yield of nil, an estimated fair value accounting price of $0.45 per share and a term of 5 years. Theascribed value of the stock options will be recognized over their vesting period. No stock options were granted duringthe three months ended September 30, 2008.

g) Per Share Amounts

During the three month period ended September 30, 2009, there were 63,544,012 (September 30, 2008 –43,096,343) weighted average shares outstanding and on a diluted basis there were 63,544,012 (September 30, 2008 –43,096,343) weighted average shares outstanding.

h) Capital Management

The Corporation’s capital management policy is to maintain a structure that optimizes the cost of capital whichconsiders the Corporation’s early stage of development and maintains investor and creditor confidence while sustainingthe future development of the business.

The Corporation manages its capital structure and makes changes to it in the light of changes in economicconditions and the risk characteristics of the underlying petroleum and natural gas assets. The Corporation considers itscapital structure to include shareholders’ equity and working capital. As at September 30, 2009 the Corporation’scapital was $49,683,701 (June 30, 2009 – $49,646,212). In order to maintain or adjust the capital structure, theCorporation may from time to time issue shares, seek debt financing and adjust its capital spending to manage itscurrent and projected capital structure.

The Corporation currently has no debt outstanding and it monitors capital based on its current working capital,projected cash flow from operations and anticipated capital expenditures. In order to manage its capital structure theCorporation prepares annual capital expenditure budgets, which are updated as necessary depending on varying factorsincluding current and forecast crude oil and natural gas prices, capital deployment and general industry conditions. Theannual and updated budgets are approved by the Corporation’s Board of Directors.

The Corporation’s only externally imposed capital requirement is the covenant with the Lender that it will notpermit a working capital deficiency (including any undrawn portion of the facility in current assets and excludingamounts drawn on the facility from current liabilities). No amounts have been drawn on the facility as of September 30,2009. The Corporation has not paid or declared any dividends since the date of incorporation and does not contemplatedoing so in the foreseeable future. There were no changes in the Company’s approach to capital management sinceJune 30, 2009.

8. CONTRIBUTED SURPLUS

Three Months EndedSept. 302009

Year EndedJune 302009

$ $

Balance, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,528,574 454,015Stock based compensation expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74,550 (19,521)Disposition of property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 2,094,080

Balance, end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,603,124 2,528,574

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9. FINANCIAL INSTRUMENTS

The Corporation holds various forms of financial instruments. The nature of these instruments and theCorporation’s operations expose the Corporation to interest rate risk, credit concentration risk, industry credit risk andcommodity price risk. The Corporation manages its exposure to these risks by operating in a manner that minimizes itsexposure to the extent practical.

Credit risk

A substantial portion of the Corporation’s accounts receivable is with commodity marketers and joint venturepartners in the petroleum and natural gas industry and is subject to normal industry credit risk. The Corporationmitigates this risk by dealing only with well established marketing companies and routinely following up on itsreceivable balances. If significant capital expenditures are to be incurred on behalf of joint venture partners theCorporation will usually collect cash call funds from the joint venture partners prior to incurrence of the expenditures.As at September 30, 2009, all of the Corporation’s cash was held at one financial institution.

Interest rate risk

The Corporation is exposed to interest rate risk to the extent that its credit facility is at a floating rate of interestand its cash and cash equivalents are being held in an interest bearing account.

Risk management activities

The nature of the Corporation’s operations results in exposure to fluctuations in petroleum and natural gas prices,foreign exchange rates and interest rates. The Corporation monitors, and when appropriate, may use derivativefinancial instruments to manage its exposure to these risks. The Corporation did not enter into any derivative financialinstruments during the three months ended September 30, 2009 and has no outstanding derivative financial instrumentsas at September 30, 2009.

10. SUPPLEMENTARY CASH FLOW INFORMATION

Interest paid on a cash basis for the three months ended September 30, 2009 was $3,560 (September 30, 2008 –$1,824). The following table details the changes in non-cash working capital for the three months ended September 30:

2009 2008

$ $Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65,493 838,228Prepaid expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,272 37,841Marketable securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (150,005) —Accounts payable and accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 426,905 (498,869)

Net change in non-cash working capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 357,665 377,200

Related to:Operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 392,032 237,172Investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (34,367) 140,028

Net change in non-cash working capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 357,665 377,200

11. COMMITMENTS

In addition to the commitments referred to below, commitments and contingencies exist under various agreementsand operations in the normal course of the Corporation’s business.

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The Corporation is committed to payments under an operating lease for its office premises with the followingaggregate minimum lease payments to the expiration of the lease on April 30, 2010:

$

2009 (remainder) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28,8322010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38,443

In addition, the Corporation is required to pay its share of operating expenses, utilities and taxes for the durationof the office premises lease.

The Corporation entered into a sub-lease agreement with a private company that is required to pay rent of $4,000per month to the Corporation commencing on June 1, 2009 until April 30, 2010. The sub-lease agreement alsostipulates that during this period the private company is required to lease three parking stalls from the Corporation atprevailing market rates.

The Corporation has entered into various employment agreements that require severance payments in the event oftermination of employment without cause or certain change in control events. As at September 30, 2009 theCorporation is committed to severance obligations of $529,500 pursuant to these employment agreements. Asmanagement believes there is a high degree of probability that such severance obligations will be paid, the Corporationhas recorded $529,500 to general and administrative expenses with a corresponding amount being recorded to accountspayable and accrued liabilities. Subsequent to September 30, 2009 the Corporation paid $529,500 in severance toformer employees pursuant to the terms of these employment agreements.

12. RELATED PARTY TRANSACTIONS

During the three months ended September 30, 2009 the Corporation was not involved in any related partytransactions.

13. CONTINGENCIES

(a) The Corporation is subject to various regulatory and statutory requirements relating to the protection of theenvironment. These requirements, in addition to contractual agreements and management decisions, result inthe accrual of estimated future removal and site restoration costs. Any changes in these estimates will affectfuture operations. Costs attributable to these commitments and contingencies are expected to be incurred overan extended period of time and are to be funded mainly from the Corporation’s cash provided by operatingactivities. Although the ultimate impact of these matters on operations cannot be determined at this time, itcould be material for any one period.

(b) Under the terms of the by-laws of the Corporation, the Corporation indemnifies individuals who have actedat the Corporation’s request to be a director and/or officer of the Corporation, to the extent permitted by law,against any and all damages, liabilities, costs, charges or expenses suffered by or incurred by the individualsas a result of their service. The claims covered by such indemnifications are subject to statutory and otherlegal limitation periods. The nature of the indemnification agreements prevents the Corporation from makinga reasonable estimate of the maximum potential amount it could be required to pay to beneficiaries of suchindemnification agreements.


Except as noted elsewhere in the financial statements, the Corporation was involved in the following eventssubsequent to September 30, 2009:

(a) During the three months ended September 30, 2009 Corporation entered into an agreement with a privateinvestment company (the “Advisor”) to provide financial advisory services to the Corporation. Pursuant tothe agreement, the Advisor was paid a non-refundable work fee of $20,000, will be reimbursed for up to$5,000 of related expenses and will be paid a transaction fee of 1.00% of the calculated value of any

FS-76



successful transaction, subject to a minimum fee of $300,000. The Advisor will provide the Corporation withassistance in identifying and evaluating the potential sale of all or a portion of the Corporation’s business andoperations to Tourmaline Oil Corp. (“Tourmaline”), by means of an asset sale, take-over, merger,recapitalization, arrangement, amalgamation or any combination thereof. Subsequent to September 30, 2009the Corporation paid the Advisor a net transaction fee of $443,720 and expenses of $1,563.

(b) Subsequent to September 30, 2009, pursuant to the exercise of 308,334 stock options with an exercise priceof $0.20 per share and 656,666 stock options with an exercise price of $0.45 per share, the Corporationissued 965,000 Common Shares to certain officers, one director and one employee of the Corporation.

(c) Subsequent to September 30, 2009, the Corporation paid $45,000 for the cancellation of 779,900 BrokerWarrants (note 7[d]).

(d) On September 30, 2009 the Corporation and Tourmaline, a private oil and gas exploration company, enteredinto an agreement (the “Arrangement Agreement”) pursuant to which Tourmaline will acquire all of theissued and outstanding Common Shares of the Corporation under a plan of arrangement (the“Arrangement”). The Arrangement Agreement provides shareholders of the Corporation the right to elect toreceive, subject to adjustments: (i) 0.05904 of a Tourmaline common share for each one (1) Common Shareof the Corporation; (ii) $0.70849 in cash for each one (1) Common Share of the Corporation; or (iii) acombination of (i) and (ii) subject, in each case, to pro ration up to a maximum of $5,000,000 in cash. For theArrangement to proceed, it must be approved by at least 66.67% of the Corporation’s shareholders. At aspecial meeting of the shareholders of the Corporation held on November 9, 2009 the Arrangement wasapproved and on November 10, 2009 the Arrangement was completed and the Corporation became a whollyowned subsidiary of Tourmaline.

(e) Subsequent to September 30, 2009, pursuant to articles of amalgamation filed effective January 1, 2010, theCorporation, Tourmaline and Pienza Petroleum Inc. amalgamated and are continuing under the nameTourmaline.

15. COMPARATIVES

Certain of the prior period amounts have been reclassified to conform to the current period presentation.

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Vigilant Exploration Inc.

CONSOLIDATED FINANCIAL STATEMENTSFor the year ended June 30, 2009

Contents

Auditors’ Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FS-79

Consolidated Financial Statements

Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FS-80Statements of Operations and Deficit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FS-81Statements of Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FS-82Notes to Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FS-83-97

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Tel: 403 266 5608Fax: 403 233 7833www.bdo.ca

BDO Canada LLP620, 903 - 8th Avenue SWCalgary AB T2P 0P7 Canada

Auditors’ Report

To the Directors ofVigilant Exploration Inc.

We have audited the balance sheets of Vigilant Exploration Inc. as at June 30, 2009 and 2008 and the statementsof operations and deficit and cash flows for the years then ended. These financial statements are the responsibility ofthe Company’s management. Our responsibility is to express an opinion on these financial statements based on ouraudits.


In our opinion, these financial statements present fairly, in all material respects, the financial position of theCompany as at June 30, 2009 and 2008 and the results of its operations and its cash flows for the years then ended inaccordance with Canadian generally accepted accounting principles.


Calgary, AlbertaOctober 30, 2009

BDO Dunwoody LLP is a Limited Liability Partnership registered in Ontario

FS-79


Consolidated Balance SheetsAs At June 30,

2009 2008

$ $

ASSETSCURRENT

Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,598,934 2,913,262Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,183,734 3,128,467Prepaid expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,272 80,782

10,797,940 6,122,511Long-term deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 311,083 224,876Property and equipment (note 4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32,606,968 20,300,640

43,715,991 26,648,027

LIABILITIESCURRENT

Accounts payable and accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,008,539 2,530,301Preferred share (note 7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1

2,008,540 2,530,302Asset retirement obligations (note 6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 850,639 348,230

2,859,179 2,878,532

SHAREHOLDERS’ EQUITYEquity instruments (note 9) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65,327,887 47,159,162Contributed surplus (note 10) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,528,574 454,015Deficit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (26,999,649) (23,843,682)

40,856,812 23,769,495

43,715,991 26,648,027


APPROVED BY THE BOARD

“Daniel Wilson” Director

“Andrew Evans” Director

The accompanying notes are an integral part of these consolidated financial statements

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Consolidated Statements of Operations and DeficitYear Ended June 30,

2009 2008

$ $

REVENUEPetroleum and natural gas sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,863,488 8,846,647Royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,589,958) (1,409,040)Royalty income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64,556 49,162Interest and other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78,430 92,023

7,416,516 7,578,792

EXPENSESOperating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,333,090 1,265,576General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,558,266 2,687,447Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19,044 15,456Depletion, depreciation and accretion (note 4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,681,604 28,688,607Stock-based compensation (note 9[f]) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (19,521) 223,120

10,572,483 32,880,206

LOSS BEFORE TAXES (3,155,967) (25,301,414)

TAXES (note 8)Current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — —Future income tax recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — (1,741,422)

— (1,741,422)

NET LOSS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,155,967) (23,559,992)DEFICIT, BEGINNING OF YEAR . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (23,843,682) (283,690)

DEFICIT, END OF YEAR . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (26,999,649) (23,843,682)

Net loss per share – basic and diluted (note 9[g]) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (0.07) $ (0.57)


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Consolidated Statements of Cash FlowsYear Ended June 30,

2009 2008

$ $

CASH FLOWS RELATED TO THE FOLLOWING ACTIVITIES:

OPERATINGNet loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,155,967) (23,559,992)Adjustments for items not affecting cash:

Depletion, depreciation and accretion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,681,604 28,688,607Stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (19,521) 223,120Future income tax recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — (1,741,422)

2,506,116 3,610,313Changes in non-cash working capital (note 12) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148,875 385,536

2,654,991 3,995,849

FINANCINGShare issue costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (124,080) —Issuance of shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 5,000,000Repayment of due to related party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — (40,125)

(124,080) 4,959,875

INVESTINGAdditions to property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,472,766) (8,210,778)Dispositions of property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,340,183 —Increase in long-term deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (35,219) (23,471)Cash acquired on acquisition of Outrider (note 3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,372,670 —Changes in non-cash working capital (note 12) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 949,893 (596,828)

4,154,761 (8,831,077)

NET INCREASE IN CASH AND CASH EQUIVALENTS . . . . . . . . . . . . . . . . . . . . . . . . 6,685,672 124,647CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR . . . . . . . . . . . . . . . . . . . . 2,913,262 2,788,615

CASH AND CASH EQUIVALENTS, END OF YEAR . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,598,934 2,913,262


FS-82


Notes to the Consolidated Financial StatementsJune 30, 2009 and 2008

1. NATURE OF OPERATIONS AND BASIS OF PRESENTATION

Vigilant Exploration Inc. (the “Corporation”) was incorporated under the Canada Business Corporations Act onOctober 14, 2003. The Corporation’s principal business is the acquisition, exploration and development of oil and gasproperties in Western Canada.

These consolidated financial statements have been prepared on a basis applicable to a continuing entity inaccordance with Canadian generally accepted accounting principles (“GAAP”). The successful future operations of theCorporation are dependent on its ability to secure sufficient funds through financings, borrowings and operations to beable to meet the Corporation’s obligations as they become due. As at June 30, 2009, the Corporation had a deficit of$26,999,649 and a working capital surplus, including long-term deposits, of $9,100,483 and for the year then endedincurred a net loss of $3,155,967 and generated cash in operating activities of $2,654,991. During the year endedJune 30, 2009, the Corporation entered into an agreement with a Canadian banking institution to provide an additionalsource of financing (note 5). Although management believes the Corporation’s capital structure (note 9[h]) is sufficientas at June 30, 2009, the Corporation’s exploration and development activities are inherently uncertain and there can beno certainty that sufficient resources will be available to undertake such activities. The Corporation’s future operationsmay be altered if the potential transaction (note 16 [d]) is successfully completed.


The consolidated financial statements of the Corporation have been prepared by management in accordance withCanadian generally accepted accounting principles. The preparation of financial statements in conformity with GAAPrequires management to make estimates and assumptions that affect the amounts reported in the financial statementsand accompanying notes. Actual results could differ from those estimates. The financial statements have, inmanagement’s opinion, been properly prepared using careful judgment with reasonable limits of materiality and withinthe framework of the significant policies summarized below.

Changes in accounting policies

Effective July 1, 2008, the Corporation adopted the following new accounting standards that were issued by theCanadian Institute of Chartered Accountants (“CICA”):

Š CICA Handbook Section 1400 – “General Standards of Financial Statement Presentation” requiresmanagement to assess the Corporation’s ability to continue as a going concern, and to disclose any materialuncertainties related to events or conditions that may cast significant doubt upon the Corporation’s ability tocontinue as a going concern (note 1); and

Š CICA Handbook Section 1535 – “Capital Disclosures” requires additional disclosure of objectives, policiesand processes for managing capital. In addition, disclosure will provide commentary on the compliance withexternally imposed capital requirements (note 9[h]).

Recent accounting pronouncements that have been issued but are not yet effective, and may have potentialimplications for the Corporation are as follows:

Š CICA Handbook Section 1000 – “Financial Statement Concepts” has been amended to focus on thecapitalization of costs that truly meet the definition of an asset and de-emphasizes the matching principle.The revised requirements are effective for financial statements relating to fiscal years beginning on or afterOctober 1, 2008. The Corporation is currently assessing the impact of this new standard; and

Š CICA Handbook Section 3064 – “Goodwill and Intangible Assets” establishes standards for the recognition,measurement, presentation and disclosure of goodwill and intangible assets subsequent to their initialidentification and also provides guidance on the recognition of internally developed intangible assets. TheCorporation is currently assessing the impact of this new standard.

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Basis of consolidation

The consolidated financial statements include the accounts of the Corporation and its wholly owned subsidiary,Outrider Energy Ltd. (“Outrider”). The results of operations of Outrider are included from the acquisition date (note 3).All intercompany transactions and balances have been eliminated on consolidation.

Joint operations

A portion of the Corporation’s exploration, development and production activities may be conducted jointly withothers and accordingly, the accounts reflect only the Corporation’s proportionate interest in such activities.

Cash and cash equivalents

Cash and cash equivalents consists of cash on hand, bank balances, and term instruments with maturity dates of 90days or less.

Long-term deposits

Long-term deposits consist of deposits relating to crown royalties, licenses and office premises that are notexpected to be returned within the current year.

Property and equipment

Petroleum and natural gas properties

The Corporation accounts for its petroleum and natural gas operations in accordance with the CICA’s guideline onfull cost accounting in the petroleum and natural gas industry whereby all costs related to the acquisition, explorationand development of petroleum and natural gas reserves are capitalized in one Canadian cost centre and charged tooperations as set out below. Such costs may include land and lease acquisition costs, geological and geophysical costs,annual charges on non-producing properties, costs of drilling both productive and non-productive wells, wellequipment costs and overhead charges directly related to acquisitions or exploration and development activities.Proceeds from the sale of petroleum and natural gas properties are applied against capitalized costs, with no gain orloss recognized, unless such a sale would result in a change in the rate of depletion of more than 20%.

Office furniture and equipment

Office furniture and equipment costs are capitalized and include items such as furniture, office equipment,computer equipment, computer software and leasehold improvements.

Depletion and depreciation

The Corporation calculates depletion on its petroleum and natural gas properties, production equipment andgathering facilities using the unit-of-production method based on the estimated gross (before royalties) proved reservesof petroleum and natural gas as determined by independent reserves evaluators. Included in costs subject to depletionand depreciation are costs to develop proved reserves. Petroleum and natural gas reserves and production are convertedat a ratio of six thousand cubic feet of natural gas to one barrel of oil for depletion and depreciation purposes. Costs ofacquiring and evaluating unproved properties are initially excluded from the depletion calculation until it is determinedwhether or not proved reserves are attributable to these properties or impairment occurs. Properties excluded from thedepletion calculation are assessed in each reporting period to ascertain whether impairment has occurred. When provedreserves are assigned or the property is considered to be impaired, the cost of the property or the amount of theimpairment is added to costs subject to the depletion calculation.

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Depreciation of office furniture and equipment is provided at rates designed to amortize the cost of the assets overtheir estimated useful lives as follows:

Furniture – 20%, declining balanceOffice equipment – 30%, declining balanceComputer equipment – 30%, declining balanceComputer software – 100%, declining balanceLeasehold improvements – Over term of lease

Impairment

Petroleum and natural gas properties are evaluated in each reporting period to determine that the carrying amountsare recoverable and do not exceed the fair value of the properties. The carrying amounts are assessed to be recoverableif the sum of the undiscounted cash flows expected from the production of proved reserves and the lower of cost andmarket of unproved properties exceeds the carrying value of the petroleum and natural gas properties. If it isdetermined that the carrying value is not recoverable, an impairment loss is recognized and included in depletion anddepreciation to the extent that the carrying value exceeds the sum of the discounted cash flows expected from theproduction of proved and probable reserves and the lower of cost and market of unproved properties. The cash flowsare estimated using forecast future product prices and costs and are discounted using a risk-free interest rate.

Asset retirement

Asset retirement costs and the liabilities associated with the retirement of tangible long-lived assets, such asproducing well sites and natural gas processing plants, are initially measured at a fair value which approximates thecost a third party would incur in performing the tasks necessary to retire such assets. The fair value is recognized in thefinancial statements at the present value of expected future cash outflows to satisfy the obligation. The liability isadjusted each reporting period to reflect of the passage of time, with the accretion charged to operations, and forrevisions to the estimated future cash flows. Actual costs incurred upon settlement of the obligations are chargedagainst the liability with any difference recognized in operations. The asset retirement costs are amortized using theunit-of-production method based on estimated proved reserves.

Flow-through shares

The Corporation has financed a portion of its exploration and development activities through proceeds receivedfrom the issue of shares on a flow-through basis. Under the terms of the flow-through agreements, the resourceexpenditure deductions for income tax purposes are renounced to investors in accordance with tax legislation. TheCorporation records the carrying value of the resource expenditures in capital assets. To reflect the fact that the taxpools related to the resource expenditures are no longer available for use by the Corporation, a future income taxliability is recognized at the time the expenditures are renounced to investors and the stated value of the share capital isreduced accordingly.

Revenue recognition

Revenue from the sale of petroleum and natural gas is recognized when volumes are delivered to customers atcontractual delivery points. Transportation costs are included in production costs.

Stock-based compensation plan

The Corporation has a stock-based compensation plan as described in Note 9[e]. The Corporation measures allstock based payments using the fair value method of accounting and recognizes the compensation expense in thefinancial statements. The fair value is measured at the grant date and charged to operations over the vesting period witha corresponding increase in contributed surplus. Consideration paid on exercise of options is credited to share capital.None of the Corporation’s awards call for settlement in cash or other assets.

FS-85



Income taxes

The Corporation follows the asset and liability method of accounting for income taxes. Under this method, futureincome tax assets and liabilities are measured based upon the temporary differences between the carrying values ofassets and liabilities and their income tax basis. Future income tax expense (recovery) is computed based on the changeduring the year in the future income tax assets and liabilities. Future income tax assets are recognized to the extent it ismore likely than not that sufficient future taxable income will be available to allow the future income tax asset to berealized. Effects of changes in tax laws and tax rates are recognized when substantively enacted.

Per share amounts

Per share amounts are calculated using the total weighted average number of Common Shares outstanding duringthe year. The number of Special Voting Shares outstanding is not included in the computation of the weighted averagenumber of shares, as the Special Voting Shares have no dividend or other equity entitlements (note 9). Diluted pershare calculations reflect the exercise or conversion of potentially dilutive securities at the later of the date of grant ofsuch securities or the beginning of the period. The Corporation computes diluted earnings per share using the treasurystock method to determine the dilutive effect of stock options.

Financial instruments

The Corporation’s financial instruments that are included in the balance sheet are comprised of cash and cashequivalents, accounts receivable and accounts payable and accrued liabilities. The fair market value of these financialinstruments approximate their carrying value due to the short-term nature of these instruments. A substantial portion ofthe Corporation’s accounts receivable are with commodity marketers and joint venture partners in the petroleum andnatural gas industry and are subject to normal industry credit risk.

From time to time, the Corporation may utilize derivative financial instruments in its management of exposures tofluctuations in petroleum and natural gas prices, foreign currency exchange rates and interest rates. Gains and lossesrelating to commodity derivative contracts that meet hedge criteria are recognized as part of petroleum and natural gassales in the same period that the transactions are settled. The fair values of such derivative instruments are not recordedin the balance sheet.

Measurement uncertainty

The amounts recorded for depletion and depreciation of petroleum and natural gas properties and the provision forasset retirement costs and obligations are based on estimates. The ceiling test is based on estimates of proved reserves,production rates, oil and gas prices, future costs and other relevant assumptions. By their nature, these estimates aresubject to measurement uncertainty and the effect on the financial statements of changes in estimates in future periodscould be significant.

The financial statements include accruals based on the terms of purchase and sale agreements and other jointagreements. Due to varying interpretations of the definition of terms in these agreements the accruals made bymanagement in this regard may be different from that determined by the other parties to these agreements. The effecton the financial statements resulting from such adjustments, if any, will be accounted for prospectively.

The tax pool classifications of capital expenditures with respect to the renouncement of flow-through shares havebeen determined by the Corporation based on technical information, which may differ from the classifications made bytaxation authorities.

The operations of the Corporation are complex, and related tax interpretations, regulations and legislation arecontinually changing.

FS-86



The Black-Scholes option valuation model was developed for use in estimating the fair value of exchangeableoptions. In addition, option valuation models require the input of highly subjective assumptions including the expectedstock price volatility. Because changes in the subjective input assumptions can materially affect the fair value estimate,in management’s opinion, the existing models do not necessarily provide a reliable single measure of the fair value ofits employee options.

3. ACQUISITION

On April 17, 2009 the Corporation entered into a pre-acquisition agreement with Outrider, a private oil and gasexploration company, and on April 20, 2009 delivered an exempt take-over bid (the “Offer”) to Outrider shareholdersto acquire all of the issued and outstanding common shares of Outrider (the “Acquisition”). The consideration underthe Offer was 0.779013 of a Common Share of the Corporation for each Outrider common share. The Acquisitionclosed on April 30, 2009 and resulted in the issuance of 19,000,000 Common Shares of the Corporation, with18,647,495 Common Shares being issued on April 30, 2009 and 352,505 Common Shares being issued on May 1,2009, in exchange for 100% of the issued and outstanding common shares of Outrider.

The Acquisition was recorded at the carrying value of the net assets acquired of $18,292,805, as Outrider and theCorporation are related by common controlling shareholders and there was no substantive change in ownership of thenet assets acquired.

The Acquisition has been accounted for at the carrying values as follows:

$

Consideration:19,000,000 Common Shares (note 9[b]) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18,292,805

Net assets acquired:Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,372,670Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 331,332Prepaid expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21,532Long-term deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50,988Property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16,671,701Accounts payable and accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (742,577)Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (412,841)

18,292,805

4. PROPERTY AND EQUIPMENT

2009$

2008$

CostPetroleum and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80,219,847 54,534,557Office furniture and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 963,105 519,106

81,182,952 55,053,663

Accumulated depletion, depreciation and impairmentPetroleum and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (47,749,723) (34,423,969)Office furniture and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (826,261) (329,054)

(48,575,984) (34,753,023)

32,606,968 20,300,640

FS-87



Costs related to undeveloped properties of $347,000 (2008 – $2,000,000) have been excluded from the depletionand depreciation calculation. Future development costs of proved reserves of $4,269,000 (2008 – $nil) have beenincluded in the depletion and depreciation calculation. The Corporation does not capitalize direct general andadministrative costs.

The Corporation performed a ceiling test calculation at June 30, 2009, that resulted in an impairment charge of$nil (2008 – $21,943,000), which was included in depletion and depreciation for the years ended June 30, 2009 and2008. The recorded impairment charge in the year ended June 30, 2008 was based on a combination of future cashflows and information received from a fully marketed sale process of the Corporation. The future benchmark pricesused by the Corporation in estimating future cash flows were based on forecasts by independent reserves evaluators,adjusted for quality and transportation differentials, and are summarized as follows:

WTI Oil($US/bbl)

ForeignExchange

Rate

Edmonton ParOil

($Cdn/bbl)

AECO-CSpot Gas

($Cdn/mmbtu)

2009 (6 months) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69.47 0.850 79.92 4.362010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73.62 0.875 82.32 6.152011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76.85 0.900 83.55 6.852012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84.39 0.925 89.37 7.232013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92.01 0.950 94.97 7.50Escalate thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0% per year 0.950 2.0% per year 2.0% per year

5. BANK INDEBTEDNESS

The Corporation has a $6,500,000 (2008 – $7,000,000) demand revolving operating loan by way of currentaccount overdraft with a Canadian banking institution (the “Lender”) that also allows the Corporation the ability toissue letters of credit up to an aggregate maximum amount of $1.0 million that reduces the amount available undercurrent account overdraft. This credit facility bears interest at prime plus 0.85% (2008 – 0.35%), includes a standby feeof 0.20% (2008 – 0.10%) on the undrawn portion and is secured by a general security agreement.

Borrowings under the credit facility are subject to a maximum amount equal to the Corporation’s borrowing baseas determined by the Lender. The credit facility includes certain financial covenants that the Corporation will not atany time, without the consent of the Lender, breach the following restrictions: (i) permit the working capital ratio of theCorporation to fall below 1.00:1; or (ii) permit the Corporation’s net debt to trailing cash flow to exceed 3.00:1. TheLender defines working capital ratio as the ratio of (i) current assets plus any undrawn availability under the creditfacility to (ii) current liabilities less any amount drawn under the credit facility. The Lender defines net debt as theCorporation’s total debt less current assets; defines cash flow as the Corporation’s revenue less expenses plus futureincome taxes, amortization and other non-cash charges; and defines trailing cash flow as the Corporation’s cash flowfor the most recently completed fiscal quarter, annualized.

As at June 30, 2009 no amount (2008 – $nil) was drawn on this facility, except for letters of credit in the amount of$53,000 (2008 – $nil). Interest expense in the year ended June 30, 2009, includes a renewal fee of $9,750 (2008 – $7,000).


2009$

2008$

Balance, beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 348,230 272,380Liabilities incurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47,357 69,919Change in estimate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,815 (12,396)Accretion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32,396 18,327Acquired on acquisition of Outrider (note 3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 412,841 —

Balance, end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 850,639 348,230

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The undiscounted amount of expected cash flows required to settle the asset retirement obligation is estimated at$1,712,630 (2008 – $923,000). The Corporation expects these obligations to be settled at various times untilapproximately 2052, with the majority of the costs being incurred between 2017 and 2030. The liability for theexpected cash flows, as reflected in the financial statements, has been discounted at credit adjusted risk free rates of6.50% and 9.95%, and an inflation rate of 2.0%. The costs attributable to the future asset retirement obligations areexpected to be funded mainly from the Corporation’s cash provided by operating activities.

7. PREFERRED SHARE

The Corporation has one issued and outstanding preferred share (note 9[a]), which is redeemable and retractable at$1.00 per share plus all declared and unpaid dividends thereon. As this preferred share is retractable at the option of theholder and redeemable at the option of the Corporation, a liability in the amount of $1 has been reflected in theCorporation’s financial statements. Subsequent to June 30, 2009 the Corporation provided a notice of redemption to theholder of the preferred share; whereby, on November 9, 2009 the Corporation will redeem the preferred share at aredemption price equal to $1.

8. INCOME TAXES

The provision for income taxes differs from the result that would be computed by applying the combinedCanadian federal and provincial tax rates of approximately 29.25% (2008 – 29.50%) to the loss before taxes. Thedifference results from the following items:

2009 2008

$ $

Computed expected income tax recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (923,120) (7,463,917)Increase (decrease) in taxes resulting from:

Resource related amounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 2,964Stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5,710) 65,820Tax rate changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 163,776 906,019Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 413,587 (6,298)Future income tax benefit not recognized . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 351,467 4,753,990

Income tax recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — (1,741,422)

The Corporation has recorded a future income tax asset (liability), as at June 30, 2009, that relates to the followingtemporary differences:

2009 2008

$ $

Property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,856,409 4,578,827Non-capital losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,524,912 85,157Share issue costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139,092 90,006Valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (7,520,413) (4,753,990)

Net future income tax asset (liability) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — —

As at June 30, 2009, the Corporation had total tax pools of approximately $59,595,000 (2008 –$38,795,000) available for deduction against future taxable income.

FS-89



9. EQUITY INSTRUMENTS

a) Authorized

Unlimited number of Common Shares, which have the right to vote, receive dividends and to receive theremaining property of the Corporation on dissolution. Unlimited number of Special Voting Shares, which have theright to vote and no entitlement to receive dividends or to receive the remaining property of the Corporation ondissolution.

Unlimited number of Preferred Shares, which are retractable at the option of the holder or redeemable at theoption of the Corporation at a price of $1.00 per share and have no entitlement to receive dividends or to receive theremaining property of the Corporation on dissolution (note 7).

b) Issued and Outstanding

Number ofShares

Amount$

Common SharesBalance, June 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39,971,343 42,079,162

Issued for cash (note 9[c]) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,125,000 5,000,000

Balance, June 30, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43,096,343 47,079,162Issued for acquisition of Outrider (note 3), net of issue costs of $124,080 . . . . . . . . . . . . . 19,000,000 18,168,725

Balance, June 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62,096,343 65,247,887

Special Voting SharesBalance, June 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,125,000 —

Cancelled (note 9[c]) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,125,000) —

Balance, June 30, 2008 and 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — —

Warrants (note 9[d])Broker warrants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 779,900 80,000Warrant B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,938,000 —

Balance, June 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,717,900 80,000Expiry (Warrant B) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,938,000) —

Balance, June 30, 2008 and 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 779,900 80,000



c) Major Investor Units

Pursuant to a private placement on December 4, 2006, the Corporation issued 1,093,750 Major Investor Units toARC Equity Management (Fund 5) Ltd. (the “Major Investor”) at $1.60 per unit for gross proceeds of $1,750,000.Each Major Investor Unit consisted of one Common Share and nine Special Voting Shares. Pursuant to the terms of thesubscription agreement, the Corporation had a “call” right that required the Major Investor to purchase up to anadditional 9,843,750 Common Shares at a price of $1.60 per Common Share, and the Major Investor had a “put” rightthat required the Corporation to issue up to an additional 9,843,750 Common Shares at a price of $1.60 per CommonShare. The Major Investor’s “put” right was unconditional, and the Corporation’s “call” right was conditional on theprior approval of a capital expenditure program by the board of directors of the Corporation. The Corporation had anobligation to “call” all remaining amounts under the subscription agreement on or before December 4, 2008. OneSpecial Voting Share was deemed to be returned to and cancelled by the Corporation for no consideration for eachCommon Share purchased.

FS-90



On February 23, 2007, the Corporation issued 3,593,750 Common Shares to the Major Investor at a price of $1.60per share for gross proceeds of $5,750,000. Simultaneous with this issuance, 3,593,750 Special Voting Shares werecancelled without consideration.

On June 26, 2007, the Corporation issued 3,125,000 Common Shares to the Major Investor at a price of $1.60 pershare for gross proceeds of $5,000,000. Simultaneous with this issuance, 3,125,000 Special Voting Shares werecancelled without consideration.

On February 8, 2008, the Corporation issued 3,125,000 Common Shares to the Major Investor at a price of $1.60per share for gross proceeds of $5,000,000. Simultaneous with this issuance, 3,125,000 Special Voting Shares werecancelled without consideration.

d) Warrants


DescriptionWarrants

OutstandingWarrant

price

Weightedaverage



2009


Broker warrants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 217,400 $1.00 note 9[d](i) 217,400 $1.00Broker warrants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 187,500 $1.00 0.61 187,500 $1.00Broker warrants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 187,500 $1.50 0.61 187,500 $1.50Broker warrants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 187,500 $2.00 0.61 187,500 $2.00

779,900 779,900


DescriptionWarrants

OutstandingWarrant

price

Weightedaverage



2008


Broker warrants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 217,400 $1.00 note 9[d](i) 217,400 $1.00Broker warrants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 187,500 $1.00 1.61 187,500 $1.00Broker warrants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 187,500 $1.50 1.61 187,500 $1.50Broker warrants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 187,500 $2.00 1.61 187,500 $2.00

779,900 779,900

(i) Contractual life is not known at this time, as expiry is set for 12 months after a liquidity event occurs.

e) Stock Options

The Corporation has an incentive stock option plan pursuant to which the Corporation may issue Common Sharesupon the exercise of stock options that may be granted to directors, officers, employees and consultants. The planallows for stock options to be granted on up to 12% of the total number of Common Shares issued and outstanding.The exercise price, terms of vesting and expiry date of stock options are fixed by the board of directors of theCorporation at the time of grant. All outstanding options vest over a three year period from the date of grant, orotherwise as in accordance with the stock option plan, and expire five years from the date of grant. The maximumnumber of stock options available for grant as at June 30, 2009, is 7,451,561 (2008 – 5,171,561) of which 1,105,000(2008 – 4,371,667) have been granted.

FS-91



On July 31, 2009 the Corporation cancelled the existing 1,105,000 stock options that were outstanding at June 30,2009 and issued 4,485,000 stock options to directors, officers and employees of the Corporation, of which 1,175,000were exercisable at $0.20 per share and 3,310,000 were exercisable at $0.45 per share. All of these 4,485,000 stockoptions expire five years from the date of grant and vest over a three year period from the date of grant, except that308,334 stock options with an exercise price of $0.20 per share and 656,666 stock options with an exercise price of$0.45 per share, or cumulatively 965,000 stock options, vest immediately upon date of grant. Subsequent to July 31,2009 the Corporation cancelled 840,000 of these 4,485,000 stock options and these cancelled stock options had anexercise price of $0.45 per share and on cancellation date had not vested.

Options Outstanding

Options

Number ofcommonsharesissuable


Balance June 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,635,000 3,635,000 $ 1.23Forfeited August 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (106,667) (106,667) ($1.19)Granted November 19, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,435,000 1,435,000 $ 1.00Expired November 29, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (133,333) (133,333) ($1.00)Forfeited May 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (458,333) (458,333) ($1.24)

Balance, June 30, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,371,667 4,371,667 $ 1.16Forfeited July 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (135,000) (135,000) ($1.11)Expired August 29, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (91,667) (91,667) ($1.60)Forfeited October 6, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (240,000) (240,000) ($1.08)Forfeited October 22, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (176,667) (176,667) ($1.08)Expired October 29, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (115,000) (115,000) ($1.07)Forfeited November 4, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (46,667) (46,667) ($1.07)Forfeited November 7, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (166,667) (166,667) ($1.20)Forfeited December 17, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (181,667) (181,667) ($1.29)Expired January 4, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (680,000) (680,000) ($1.06)Expired January 20, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (453,333) (453,333) ($1.06)Expired February 2, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (88,333) (88,333) ($1.08)Expired February 5, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (133,333) (133,333) ($1.50)Expired March 17, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (403,333) (403,333) ($1.16)Forfeited April 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (355,000) (355,000) ($1.08)

Balance, June 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,105,000 1,105,000 $ 1.26



Weighted averageremainingcontractuallife (years)

Number ofoptions

currentlyexercisable


exercisable

625,000 $1.00 2.38 375,000 $1.00480,000 $1.60 2.68 320,000 $1.60

1,105,000 2.51 695,000 $1.28

FS-92





Weighted averageremaining contractual

life (years)Number of options

currently exercisable


exercisable

3,085,000 $1.00 2.80 1,616,668 $1.00520,000 $1.50 3.29 173,333 $1.50766,667 $1.60 3.67 316,664 $1.60

4,371,667 3.01 2,106,665 $1.13

f) Stock-based Compensation

During the year ended June 30, 2009 no stock options were granted and the forfeiture of certain stock optionsresulted in a recovery of previously recognized stock based compensation expense of $19,521. During the year endedJune 30, 2008 the Corporation granted stock options to various directors and employees to purchase up to 1,435,000Common Shares and, upon the issuance of these stock options, ascribed a value of $185,115 utilizing the Black-Scholes option valuation model with a volatility of 10%, risk-free rate of 3.7%, dividend yield of nil and a term of 5years. The ascribed value is being expensed over the option three year vesting period.

g) Per Share Amounts

During the year ended June 30, 2009, there were 46,322,774 (2008 – 41,200,851) weighted average sharesoutstanding and on a diluted basis there were 46,322,774 (2008 – 41,464,672) weighted average shares outstanding.

h) Capital Management

The Corporation’s capital management policy is to maintain a structure that optimizes the cost of capital whichconsiders the Corporation’s early stage of development and maintains investor and creditor confidence while sustainingthe future development of the business.

The Corporation manages its capital structure and makes changes to it in the light of changes in economicconditions and the risk characteristics of the underlying petroleum and natural gas assets. The Corporation considers itscapital structure to include shareholders’ equity and working capital. As at June 30, 2009 the Corporation’s capital was$49,646,212 (2008 – $27,361,704). In order to maintain or adjust the capital structure, the Corporation may from timeto time issue shares, seek debt financing and adjust its capital spending to manage its current and projected capitalstructure.

The Corporation currently has no debt outstanding and it monitors capital based on its current working capital,projected cash flow from operations and anticipated capital expenditures. In order to manage its capital structure theCorporation prepares annual capital expenditure budgets, which are updated as necessary depending on varying factorsincluding current and forecast crude oil and natural gas prices, capital deployment and general industry conditions. Theannual and updated budgets are approved by the Corporation’s Board of Directors.

The Corporation’s only externally imposed capital requirement is the covenant with the Lender that it will notpermit a working capital deficiency (including any un-drawn portion of the facility in current assets and excludingamounts drawn on the facility from current liabilities). No amounts have been drawn on the facility as of June 30,2009. The Corporation has not paid or declared any dividends since the date of incorporation and does not contemplatedoing so in the foreseeable future. There were no changes in the Company’s approach to capital management sinceJune 30, 2008.

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10. CONTRIBUTED SURPLUS

2009 2008

$ $

Balance, beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 454,015 230,895Stock based compensation expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (19,521) 223,120Disposition of property and equipment (note 14 [d]) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,094,080 —

Balance, end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,528,574 454,015

11. FINANCIAL INSTRUMENTS

The Corporation holds various forms of financial instruments. The nature of these instruments and theCorporation’s operations expose the Corporation to interest rate risk, credit concentration risk, industry credit risk andcommodity price risk. The Corporation manages its exposure to these risks by operating in a manner that minimizes itsexposure to the extent practical.

Credit risk

A substantial portion of the Corporation’s accounts receivable is with commodity marketers and joint venturepartners in the petroleum and natural gas industry and is subject to normal industry credit risk. The Corporationmitigates this risk by dealing only with well established marketing companies and routinely following up on itsreceivable balances. If significant capital expenditures are to be incurred on behalf of joint venture partners theCorporation will usually collect cash call funds from the joint venture partners prior to incurrence of the expenditures.As at June 30, 2007, the Corporation had approximately $1.3 million in outstanding receivables from an industrypartner involved in a debt restructuring process. The Corporation negotiated a payment schedule and at June 30, 2008,had received all amounts owing pursuant to this receivable. As at June 30, 2009, all of the Corporation’s cash was heldat one financial institution.

Interest rate risk

The Corporation is exposed to interest rate risk to the extent that its credit facility is at a floating rate of interestand its cash and cash equivalents are being held in an interest bearing account.

Risk management activities

The nature of the Corporation’s operations results in exposure to fluctuations in petroleum and natural gas prices,foreign exchange rates and interest rates. The Corporation monitors, and when appropriate, may use derivativefinancial instruments to manage its exposure to these risks. The Corporation did not enter into any derivative financialinstruments during 2009 or 2008 and has no outstanding derivative financial instruments as at June 30, 2009.

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12. SUPPLEMENTARY CASH FLOW INFORMATION

Interest paid on a cash basis for the year ended June 30, 2009, was $19,044 (2008 – $15,456). Capital taxes paidon a cash basis for the year ended June 30, 2009, was $nil (2008 – $nil). The following table details the changes innon-cash working capital for the years ended June 30:

2009 2008

$ $Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,276,065 255,050Prepaid expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87,042 (19,063)Accounts payable and accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,264,339) (447,279)

Net change in non-cash working capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,098,768 (211,292)

Related to:Operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148,875 385,536Investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 949,893 (596,828)

Net change in non-cash working capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,098,768 (211,292)

13. COMMITMENTS

In addition to the commitments referred to below, commitments and contingencies exist under various agreementsand operations in the normal course of the Corporation’s business.

The Corporation is committed to payments under an operating lease for its office premises with the followingaggregate minimum lease payments to the expiration of the lease on April 30, 2010:

$

2009 (remainder) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57,6642010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38,443

In addition, the Corporation is required to pay its share of operating expenses, utilities and taxes for the durationof the office premises lease.

The Corporation entered into a sub-lease agreement with a private company that is required to pay rent of $4,000per month to the Corporation commencing on June 1, 2009 until April 30, 2010. The sub-lease agreement alsostipulates that during this period the private company is required to lease three parking stalls from the Corporation atprevailing market rates.

The Corporation has entered into various employment agreements that require severance payments in the event oftermination of employment without cause or certain change in control events. As at June 30, 2009 the Corporation iscommitted to severance obligations of $529,500 pursuant to these employment agreements. Subsequent to June 30,2009 the Corporation paid $69,000 in severance to a former employee pursuant to the terms of these employmentagreements and reduced the Corporation’s severance obligations commitment to $460,500.

14. RELATED PARTY TRANSACTIONS

Except as noted elsewhere in the financial statements, the Corporation was involved in the following related partytransactions:

(a) On July 30, 2004 the Corporation received a loan in the amount of $160,500 from a related companycontrolled by a shareholder and former director to purchase 3D seismic data from the related company. The$160,500 loan was repayable in 4 annual installments of $40,125, bears no interest and is unsecured. As atJune 30, 2008, the loan balance owing to the related company was $nil.

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(b) During the year ended June 30, 2009, the Corporation issued nil (2008 – 3,125,000) Common Shares to theMajor Investor, which is a party related to certain directors of the Corporation.

(c) During the year ended June 30, 2009 the Corporation paid the agreed to exchange amount of $nil (2008 –$500,000) to a company controlled by a shareholder and former director to purchase 3D seismic data fromthe company.

(d) During the year ended June 30, 2009 the Corporation received proceeds of $2,204,923 (2008 – $nil) from adisposition of property and equipment from a company with common controlling shareholders to theCorporation. The difference of $2,094,080 (2008 – $nil) between the carrying value of the property andequipment disposed of and the proceeds of disposition was recorded to contributed surplus (note 10).

(e) During the year ended June 30, 2009 the Corporation issued 19,000,000 Common Shares to acquire all of theissued and outstanding common shares of Outrider (note 3), a company with common controllingshareholders.

Except as otherwise disclosed these transactions have been recorded at the agreed to exchange amount.

15. CONTINGENCIES

(a) The Corporation is subject to various regulatory and statutory requirements relating to the protection of theenvironment. These requirements, in addition to contractual agreements and management decisions, result inthe accrual of estimated future removal and site restoration costs. Any changes in these estimates will affectfuture operations. Costs attributable to these commitments and contingencies are expected to be incurred overan extended period of time and are to be funded mainly from the Corporation’s cash provided by operatingactivities. Although the ultimate impact of these matters on operations cannot be determined at this time, itcould be material for any one period.

(b) Under the terms of the by-laws of the Corporation, the Corporation indemnifies individuals who have actedat the Corporation’s request to be a director and/or officer of the Corporation, to the extent permitted by law,against any and all damages, liabilities, costs, charges or expenses suffered by or incurred by the individualsas a result of their service. The claims covered by such indemnifications are subject to statutory and otherlegal limitation periods. The nature of the indemnification agreements prevents the Corporation from makinga reasonable estimate of the maximum potential amount it could be required to pay to beneficiaries of suchindemnification agreements.


Except as noted elsewhere in the financial statements, the Corporation was involved in the following eventssubsequent to June 30, 2009:

(a) Subsequent to June 30, 2009, pursuant to articles of amalgamation filed effective July 1, 2009, theCorporation and its wholly owned subsidiary 7198621 Canada Inc. (formerly Outrider) amalgamated and arecontinuing under the name Vigilant Exploration Inc.

(b) Subsequent to June 30, 2009 the Corporation entered into an agreement with a private investment company(the “Advisor”) to provide financial advisory services to the Corporation. Pursuant to the agreement, theAdvisor was paid a non-refundable work fee of $20,000, will be reimbursed for up to $5,000 of relatedexpenses and will be paid a transaction fee of 1.00% of the calculated value of any successful transaction,subject to a minimum fee of $300,000. The agreement expires on December 31, 2009 and the transaction feeis payable in respect of any transaction announced during the period ending December 31, 2009. The Advisorwill provide the Corporation with assistance in identifying and evaluating the potential sale of all or a portionof the Corporation’s business and operations to Tourmaline Oil Corp. (“Tourmaline”), by means of an assetsale, take-over, merger, recapitalization, arrangement, amalgamation or any combination thereof.

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(c) Subsequent to June 30, 2009 the Corporation completed a private placement issuance of 2,148,154 CommonShares at a price of $0.20 per share to certain officers and one director of the Corporation for proceeds of$429,631.

(d) Subsequent to June 30, 2009 the Corporation and Tourmaline, a private oil and gas exploration company, enteredinto an agreement (the “Arrangement Agreement”) pursuant to which Tourmaline will acquire all of the issuedand outstanding Common Shares of the Corporation under a plan of arrangement (the “Arrangement”). TheArrangement Agreement provides shareholders of the Corporation the right to elect to receive, subject toadjustments: (i) 0.05904 of a Tourmaline common share for each one (1) Common Share of the Corporation;(ii) $0.70849 in cash for each one (1) Common Share of the Corporation; or (iii) a combination of (i) and(ii) subject, in each case, to pro ration up to a maximum of $5,000,000 in cash. For the Arrangement to proceed itmust be approved by at least 66.67% of the votes cast by the Corporation’s shareholders present, in person or byproxy at a special meeting of the shareholders of the Corporation. In conjunction with the ArrangementAgreement, directors and certain officers and certain significant shareholders of the Corporation who owncollectively approximately 77.6% of the Corporation’s outstanding Common Shares, after the private placement(note 16[c]), executed support agreements pursuant to which they agreed to vote Common Shares of theCorporation held by them in favour of the Arrangement.

17. COMPARATIVES

Certain of the prior period amounts have been reclassified to conform to the current year presentation.

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EXSHAW OIL CORP.

Unaudited Financial StatementsThree and Nine Months Ended September 30, 2009

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EXSHAW OIL CORP.

Balance Sheets(Unaudited)

(Thousands of Dollars)

September 30,2009

December 31,2008


Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 459 $ 10,254Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,996 4,067Prepaid expenses and deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,136 1,114

4,591 15,435Property, plant and equipment (note 4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 161,788 167,832

$166,379 $183,267


Accounts payable and accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 5,262 $ 12,934Asset retirement obligations (note 6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,124 1,937Future income tax (note 9) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,989 6,969Shareholders’ equity:

Share capital (note 7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149,312 152,563Contributed surplus (note 7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,406 2,936Retained earnings (deficit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,714) 5,928

151,004 161,427

$166,379 $183,267


See accompanying notes to interim financial statements.

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EXSHAW OIL CORP.

Statements of Income, Comprehensive Income and Retained Earnings (Deficit)(Unaudited)



Sept. 30,2009

Sept. 30,2008

Sept. 30,2009

Sept 30,2008

Revenue:Petroleum and natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 7,536 $14,613 $24,025 $41,745Royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,116) (3,965) (3,793) (9,300)Interest and other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51 71 171 272

6,471 10,719 20,403 32,717Expenses:

Operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,784 2,622 8,298 7,127General and administration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 363 311 1,257 1,046Stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93 111 289 334Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148 3 443 121Depletion, depreciation and accretion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,664 5,626 20,049 14,571

10,052 8,673 30,336 23,199

Income (loss) before taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,581) 2,046 (9,933) 9,518Future income tax expense (reduction) (note 9) . . . . . . . . . . . . . . . . . . . . . . . . (857) 519 (2,291) 2,188

Net income (loss) and comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . (2,724) 1,527 (7,642) 7,330Retained earnings (deficit), beginning of period . . . . . . . . . . . . . . . . . . . . . . . 1,010 5,430 5,928 (373)

Retained earnings (deficit), end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (1,714) $ 6,957 $ (1,714) $ 6,957


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EXSHAW OIL CORP.

Statements of Cash Flows(Unaudited)


Three MonthsEnded

Nine MonthsEnded

Sept. 30,2009

Sept. 30,2008

Sept. 30,2009

Sept. 30,2008


Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $(2,724) $ 1,527 $ (7,642) $ 7,330Items not involving cash:

Depletion, depreciation, and accretion . . . . . . . . . . . . . . . . . . . . . . . . . . 6,664 5,626 20,049 14,571Stock-based compensation expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93 111 289 334Future income tax expense (reduction) . . . . . . . . . . . . . . . . . . . . . . . . . . (857) 519 (2,291) 2,188Change in non-cash operating working capital (note 10) . . . . . . . . . . . . 56 1,118 (18) 878

3,232 8,901 10,387 25,301Financing:

increase (decrease) in bank debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (168) — — —Investments:

Additions to property, plant, and equipment . . . . . . . . . . . . . . . . . . . . . . . . (3,157) (5,452) (13,577) (24,594)Change in non-cash investing working capital (note 10) . . . . . . . . . . . . . . 552 (1,711) (6,605) (6,672)

(2,605) (7,163) (20,182) (31,266)

Increase (decrease) in cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 459 $ 1,738 $ (9,795) $ (5,965)Cash, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 1,500 10,254 9,203

Cash, end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 459 $ 3,238 $ 459 $ 3,238

Interest received . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ 9 $ 11 $ 50



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EXSHAW OIL CORP.

Notes to Financial Statements (Unaudited)Three and Nine Months Ended September 30, 2009

(tabular amounts in thousands of dollars)

1. Nature of operations:

Exshaw Oil Corp. (the “Company”) is incorporated under the Business Corporations Act (Alberta) andcommenced field operations on December 14, 2006. The Company is engaged in the acquisition, exploration,development and production of natural gas, natural gas liquids and crude oil in the Western Canadian SedimentaryBasin.

2. Basis of Presentation:

The interim financial statements of the Company have been prepared by management in accordance withCanadian Generally Accepted Accounting Principles (“GAAP”). These interim financial statements follow the sameaccounting policies and methods as the financial statements for the year ended December 31, 2008, and include alladjustments necessary to present fairly the results for the interim period. Certain information and footnote disclosurenormally included in the annual financial statements has been omitted. These interim financial statements should beread in conjunction with the financial statements and notes for the year ended December 31, 2008.

3. Significant accounting policies:

Pending Accounting Pronouncements

International Financial Reporting Standards (“IFRS”)

In 2005 the Accounting Standards Board of Canada (“AcSB”) announced that accounting standards in Canada areto converge with IFRS. The AcSB has indicated that Canadian publically accountable entities will need to beginreporting under the IFRS by the first quarter of 2011 with appropriate comparative data from the prior year. UnderIFRS, the primary audience is capital markets, and as a result, there is significantly more disclosure required,specifically for quarterly reporting. Further, while IFRS uses a conceptual framework similar to Canadian GAAP, thereare significant differences in accounting policy which must be addressed.

4. Property, plant and equipment;

September 30, 2009 December 31, 2008

Cost

AccumulatedDepletion andDepreciation

Net BookValue

Net BookValue

Petroleum and natural gas properties . . . . . . . . . . . . . . . . . . . . . $194,632 $49,752 $144,880 $154,365Plant and facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17,966 1,179 16,787 13,326Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 224 103 121 141

$212,822 $51,034 $161,788 $167,832

General and administrative expenditures of $1,004,000 ($1,410,000 at September 30, 2008) have been capitalizedand included as costs of petroleum and natural gas properties. Included in this amount are general and administrativeexpenses of $763,000 ($1,132,000 at September 30, 2008) and non-cash related stock-based compensation of $181,000($209,000 at September 30, 2008). A future tax liability of $60,000 ($69,000 at September 30, 2008) associated withthe capitalized stock-based compensation has also been capitalized.

The cost of unproven properties in the amount of $19,956,000 ($23,134,000 at December 31, 2008) has beenexcluded from the depletion calculation. Future development costs related to proved reserves in the amount of$41,856,000 ($46,400,000 at December 31, 2008) have been included in the depletion calculation.

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EXSHAW OIL CORP.



5. Bank debt:

At September 30, 2009, the Company had a financing arrangement with a Canadian chartered bank for anextendible revolving term loan in the amount of $19 million in addition to a $5 million operating line. AtSeptember 30, 2009 the facilities were not drawn (Nil at September 30, 2008). The interest rate charged varies basedon the amount outstanding. Security for the facility includes a general security agreement and a demand loan debenturesecured by a first floating charge over all assets. The revolving term credit facility has a 364 day extendible period plusa one-year maturity. The term date of the renewed facility is May 28, 2010.

6. Asset retirement obligations:

The Company’s asset retirement obligations result from net ownership interests in petroleum and natural gasassets including well sites, gathering systems and processing facilities. The Company estimates the total undiscountedamount of cash flows required to settle its asset retirement obligations is approximately $5,007,000 (2008 –$4,984,000) (inflation adjusted) which will be incurred between 2011 and 2039. A credit-adjusted risk-free rate of 8 to10% (2008 – 8%) and an inflation rate of 2% (2008 – 2%) were used to calculate the fair value of the asset retirementobligations.

The changes in the asset retirement obligation are as follows:



Balance, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,937 $1,100Liabilities incurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80 591Revisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (9) 148Accretion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116 98


7. Share capital:

(a) Authorized:

Unlimited number of common shares

Unlimited number of preferred shares

(b) Common shares issued:

Number of Shares Amount

Balance, December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53,340,001 $152,563Tax effect of flow-through share renunciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — (3,251)

Balance, September 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53,340,001 $149,312

(c) Flow-through shares:

In the first quarter, the Company renounced $13,002,000 of Canadian Exploration Expenses related to the flow-through shares it issued in 2008. As at September 30, 2009, the Company estimates that it has an obligation of $12.4million remaining from the December 9, 2008 offering which must be spent on qualifying exploration expenses prior toDecember 31, 2009.

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EXSHAW OIL CORP.



(d) Contributed surplus:

Balance, December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,936Stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 470

Balance, September 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $3,406

(e) Stock options:

The Company has a stock option plan whereby directors, officers, employees and consultants are eligible toreceive options. Under the stock option plan, the Company may grant options for up to 10% of the outstandingcommon stock. The exercise price of each option equals the market price of the Company’s stock at the date of grant.Options vest 1⁄3 on each of the first, second and third anniversaries from the date of grant and the maximum term isfive years.

Changes in the number of options, with their weighted average exercise price, are summarized as follows:

Options Outstanding Options Exercisable

NumberOutstanding

WeightedAverageExercisePrice

WeightedAverage

RemainingContractualLife (years)

NumberExercisable At

September 30, 2009


Outstanding, December 31, 2008 . . . . . . . . . . . . . . . . 3,795,000 2.98 3.32 2,008,833 3.00Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50,000 2.75 4.41 — —

Outstanding, September 30, 2009 . . . . . . . . . . . . . . . 3,845,000 2.98 2.60 2,008,833 3.00

The Company uses the fair value based method for the determination of all stock-based compensation costs. Thefair value of each employee option granted during the year is estimated on the date of grant using the Black-Scholesoption-pricing model. The Company determines the fair value for employee stock options using the minimum valuemethod. Stock-based compensation costs in the amount of $152,500 have been recorded in the current quarter.

(f) Performance warrants:

The Company has a performance warrant plan whereby directors, officers, employees and consultants are eligibleto receive performance warrants. Under the performance warrant program, the Company may issue up to 5,775,000warrants.

The performance warrants are fully vested on issuance and are exercisable as follows:

ExercisePrice

RemainingLife (Yr)

OutstandingDecember 31,

2008 Issued

OutstandingSeptember 30,

2009Number

Exercisable

$3.50 0.20 1,124,492 — 1,124,492 1,124,492$4.50 0.20 1,124,492 — 1,124,492 1,124,492$5.50 0.20 1,124,492 — 1,124,492 1,124,492$6.50 0.20 1,124,492 — 1,124,492 1,124,492$7.50 0.20 1,124,492 — 1,124,492 1,124,492

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EXSHAW OIL CORP.



The fair value of each warrant granted during the year was estimated on the date of grant using the Black-Scholesoption-pricing model. The Company determines fair value for employee warrants using the minimum value method.No performance warrants were issued in the current period.

8. Financial instruments:

Cash and cash equivalents are designated as held-for-trading and are measured at carrying value, whichapproximates fair value due to the short-term nature of these instruments. Accounts receivable and accrued revenuesare designated as loans and receivables. Accounts payable and accrued liabilities and long-term debt are designated asother liabilities.

The Company measures and recognizes embedded derivatives separately from the host contracts when theeconomic characteristics and risks of the embedded derivative are not closely related to those of the host contract,when it meets the definition of a derivative and when the entire contract is not measured as fair value. Embeddedderivatives are recorded at fair value. The Company does not have any material embedded derivatives which requireseparate recognition and measurement.

The Company has exposure to the following risks from its use of financial instruments:

Š Credit risk

Š Liquidity risk

Š Market risk

Credit risk:

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument failsto meet its contractual obligations, and arises principally from the Company’s receivables from joint venture partnersand petroleum and natural gas marketers.

Receivables from petroleum and natural gas marketers are normally collected on the 25th day of the monthfollowing production. The Company’s policy to mitigate credit risk associated with these balances is to establishmarketing relationships with creditworthy purchasers. The Company historically has not experienced any collectionissues with its petroleum natural gas marketers. Joint venture receivables are typically collected within one to threemonths of the joint venture bill being issued to the partner. The Company attempts to mitigate the risk from jointventure receivables by obtaining partner approval of significant capital expenditures prior to expenditure. However, thereceivables are from participants in the petroleum and natural gas sector, and collection of the outstanding balances isdependent on industry factors such as commodity price fluctuations, escalating costs and the risk of unsuccessfuldrilling. In addition, further risk exists with joint venture partners as disagreements occasionally arise that increases thepotential for non-collection. The Company does not typically obtain collateral from petroleum and natural gasmarketers or joint venture partners; however, the Company does have the ability to withhold production from jointventure partners in the event of non-payment.

The Company monitors the age of and investigates issues behind its receivables that have been past due for over60 days. The Company’s accounts receivable balance at September 30, 2009 is approximately $3.0 million ($4.8million at September 30, 2008) of which $1,000 ($103,000 at September 30, 2008) of this balance has been outstandinggreater than 90 days. The Company is satisfied through its investigations that these amounts are entirely collectible.

The carrying amount of accounts receivable and cash and cash equivalents represents the maximum creditexposure. The Company does not have an allowance for doubtful accounts as at September 30, 2009 and did notprovide for any doubtful accounts, nor was it required to write-off any receivables during the period endedSeptember 30, 2009.

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EXSHAW OIL CORP.



Liquidity risk:

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they are due. TheCompany’s approach to managing liquidity is to ensure, as far as possible, that it will have sufficient liquidity to meetits liabilities when due, under both normal and stressed conditions without incurring unacceptable losses or riskingharm to the Company’s reputation.

The Company’s accounts payable and accrued liabilities balance at September 30, 2009 is approximately $5.3million ($7.0 million at September 30, 2008). It is the Company’s policy to pay suppliers within 90 days. These termsare consistent with industry standards. As at September 30, 2009, less than $67,000 ($124,000 at September 30, 2008)of the account balance is greater than 90 days. The Company reviews all balances that have been outstanding forgreater than 90 days, and has determined that acceptable business reasons exist for these accounts to be outstanding.

The Company prepares annual capital expenditure budgets which are regularly monitored and updated asconsidered necessary. Further, the Company utilizes authorizations for expenditures on both operated and non-operatedprojects to further manage capital expenditures. To facilitate the capital expenditure program, the Company has arevolving reserve-based credit facility, as outlined in Note 5, which is reviewed at least annually by the lender. TheCompany also attempts to match its payment cycle with collection of petroleum and natural gas revenues on the 25th ofeach month.

Market risk:

Commodity price risk is the risk that the fair value of future cash flows will fluctuate as a result of changes incommodity prices. The Company may utilize both financial derivatives and physical delivery sales contracts to managethis risk. Any such transactions must be approved by the Board of Directors.

Currency risk has no impact on the value of the financial assets and liabilities on the balance sheet atSeptember 30, 2009. Changes in the U.S. to Canadian exchange rate, however, could influence future petroleum andnatural gas prices which may impact the value of certain derivative contracts. This influence cannot be accuratelyquantified.

The Company is exposed to interest rate risk via fluctuations on its bank debt which bears a floating rate ofinterest. The Company had no interest rate swap or financial contracts in place as at or during the period endedSeptember 30, 2009.

Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes incommodity prices. The Company has not entered into any financial derivatives to mitigate commodity price risk at thispoint although it may in the future as its production increases.

Capital management:

The Company’s policy is to maintain a strong capital base so as to maintain investor, creditor and marketconfidence and to sustain the future development of the business. The Company considers its capital structure toinclude shareholders’ equity, bank debt and working capital deficiency. The Company may, from time to time, issueshares and adjust its capital spending to manage current and projected debt levels. The annual and updated budgets areapproved by the Board of Directors.

The key measures that the Company utilizes in evaluating its capital structure are total debt to cash flow fromoperations (before changes in non-cash working capital) and the current credit available from its creditors in relation tothe Company’s budgeted capital program. At September 30, 2009 the Company had no bank debt outstanding (Nil atSeptember 30, 2008) and a working capital deficiency of $671,000 ($2.3 Million surplus at September 30, 2008).These totals are within an acceptable range for the Company.

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EXSHAW OIL CORP.



The Company’s share capital is not subject to external restrictions; however, the bank debt facility is based onpetroleum and natural gas reserves and certain financial covenants – all of which have been met (see Note 5).

9. Income taxes:

The provision for income taxes in the financial statements differs from the result, which would have been obtainedby applying the combined federal and provincial tax rate to the Company’s earnings before income taxes. Thisdifference results from the following items:



Earnings before taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $(9,933) $9,518Combined federal and provincial tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29.0% 29.5%Computed “expected” income tax expense (reduction) . . . . . . . . . . . . . . . . . . . . . $(2,881) $2,808Increase resulting from:

Effect of change in tax rate and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 506 (384)Stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84 98

Future income tax expense (reduction) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $(2,291) $2,522

The components of the Company’s future income tax liability/(asset) are as follows:

September 30,2009

December 31,2008

Future tax assets:Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (531) $ (484)Share issue costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (924) (1,255)Non-capital loss carry-forward . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,594) (1,902)

(3,049) (3,641)Future tax liabilities:

Property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11,038 10,612

Net future tax liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 7,989 $ 6,969

10. Supplemental cash flow information:


Sept.30,2009

Sept.30,2008

Sept.30,2009

Sept.30,2008

Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 48 $1 ,461 $ 1,071 $ 342Prepaid expenses and deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94 (522) (22) (791)Accounts payable and accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . 466 (1,532) (7,672) (5,345)

Change in non-cash working capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $608 $ (593) $(6,623) $(5,794)

Relating to:Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 56 $ 1,118 $ (18) $ 878Investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 552 (1,711) (6,605) (6,672)

Change in non-cash working capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $608 $ (593) $(6,623) $(5,794)

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EXSHAW OIL CORP.



11. Commitments:

In the normal course of business, Exshaw is obligated to make future payments. The following obligationsrepresent commitments that are known and non-cancelable.

Payment due by period Total 2009 2010

Operating lease . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $199 $85 $114

Also as at September 30, 2009, the Company estimates that it has an obligation in the amount of $12.4 millionremaining from the December 9, 2008 flow-through share offering which must be spent on qualifying explorationexpenditures prior to December 31, 2009.

12. Subsequent Events:

On November 10, 2009 Tourmaline Oil Corp. (“Tourmaline”) acquired 90.6 percent of Exshaw’s outstandingcommon shares by issuing 10.875 million Tourmaline shares.

FS-108

AUDITORS’ REPORT

To the Shareholders of Exshaw Oil Corp.:

We have audited the balance sheets of Exshaw Oil Corp. as at December 31, 2008 and 2007 and the statements ofincome and retained earnings and cash flows for the years ended December 31, 2008 and 2007. These financialstatements are the responsibility of the Company’s management. Our responsibility is to express an opinion on thesefinancial statements based on our audit.


In our opinion, these financial statements present fairly, in all material respects, the financial position of theCompany as at December 31, 2008 and 2007 and the results of its operations and its cash flows for the years endedDecember 31, 2008 and 2007, in accordance with Canadian generally accepted accounting principles.


Calgary, CanadaApril 23, 2009

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EXSHAW OIL CORP.

Balance Sheets(Thousands of Dollars)

December 31 2008 2007


Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 10,254 $ 9,203Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,067 4,692Prepaid expenses and deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,114 921

15,435 14,816Future income tax (note 9) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 1,270Property, plant and equipment (note 4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 167,832 145,797

$183,267 $161,883


Accounts payable and accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 12,934 $ 12,360Asset retirement obligations (note 6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,937 1,100Future income tax (note 9) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,969 —Shareholders’ equity:

Share capital (note 7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 152,563 146,444Contributed surplus (note 7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,936 2,352Retained earnings (deficit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,928 (373)

161,427 148,423

$183,267 $161,883

Commitments (note 11)

On behalf of the Board:

(signed) “W. Peter Comber” (signed) “Joanna Wright”

W. Peter Comber Joanna WrightDirector Director


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EXSHAW OIL CORP.

Statements of Income and Retained Earnings(Thousands of Dollars)



Revenue:Petroleum and natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 51,931 $22,230Royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (11,525) (5,444)Interest and other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 332 1,280

40,738 18,066Expenses:

Operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,759 5,122General and administration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,474 1,055Stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 308 321Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 122 —Depletion, depreciation and accretion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20,709 10,339

32,372 16,837

Income before taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,366 1,229Future income taxes (note 9): . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,065 424

Net income and comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,301 805Deficit, beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (373) (1,178)

Retained earnings (deficit), end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 5,928 $ (373)


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EXSHAW OIL CORP.

Statements of Cash Flows(Thousands of Dollars)




Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6,301 $ 805Items not involving cash:

Depletion, depreciation and accretion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20,709 10,339Stock-based compensation expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 308 321Future income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,065 424Change in non-cash operating working capital (note 10) . . . . . . . . . . . . . . . . . 1,137 (305)

30,520 11,584Financing:

Issue of common shares, net of share issue costs . . . . . . . . . . . . . . . . . . . . . . . . . 12,201 23,451

Investments:Additions to property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (41,539) (67,862)Change in non-cash investing working capital (note 10) . . . . . . . . . . . . . . . . . . . (131) 7,932

(41,670) (59,930)

Increase (decrease) in cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,051 (24,895)Cash, beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,203 34,098

Cash, end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 10,254 9,203

Interest received . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 71 1,167



FS-112

EXSHAW OIL CORP.

Notes to Financial StatementsYears Ended December 31, 2008 and December 31, 2007

(tabular amounts in thousands)

Nature of operations:

Exshaw Oil Corp. (the “Company”) was incorporated under the Business Corporations Act (Alberta) onOctober 13, 2006 and commenced field operations on December 14, 2006. The Company is engaged in the acquisition,exploration, development and production of natural gas, natural gas liquids and crude oil in the Western CanadianSedimentary Basin.

1. Basis of presentation:

The financial statements of the Corporation have been prepared by management in accordance with Canadiangenerally accepted accounting principles.

2. Significant accounting policies:

(a) Property, plant and equipment:

The Company follows the full-cost method of accounting for oil and gas operations whereby all costs of exploringfor and developing oil and gas properties and related reserves are capitalized.

Such costs include land acquisition costs, cost of drilling both productive and non-productive wells, assetretirement costs and geological and geophysical expenses and overhead charges, including capitalized stock-basedcompensation and the related income tax effect, directly related to acquisition, exploration and development activities.Proceeds from the sale of petroleum and natural gas properties are applied against capitalized costs. Gains or losses onthe disposition of oil and gas properties are not ordinarily recognized except under circumstances that result in achange in the depletion rate of 20% or more.

Capitalized costs, excluding costs relating to unproved properties and estimated salvage values, are depleted usingthe unit-of-production method based on estimated proved reserves of oil and gas before royalties as determined byindependent petroleum engineers. For purposes of the depletion calculation, natural gas reserves and production areconverted to equivalent volumes of crude oil based on relative energy content.

The costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations.These properties are assessed periodically to ascertain whether impairment has occurred. When proved reserves areassigned or the property is considered to be impaired, the cost of the property or the amount of impairment is added tocosts subject to depletion.

The Company applied a “ceiling test” to capitalized costs to ensure that the net costs capitalized do not exceed theestimated future net revenues from the production of its proved reserves, plus the cost of undeveloped land, lessimpairment. Future net revenues are calculated using the undiscounted net production revenue from total provedreserves assigned by independent reserve engineers and the cost less impairment, if any, of unproved properties. Whenthe carrying amount is in excess, and is therefore assessed as not recoverable, an impairment loss would be recognizedto the extent that the carrying value of assets exceeds the sum of the discounted cash flows from the production ofproved and probable reserves, the lower of cost and market of unproved properties and the cost of major developmentprojects. The cash flows are estimated using expected future product prices and costs and are discounted using a risk-free interest rate.

Plant and facilities are amortized on a straight-line basis over their estimated useful life of 25 years.

Depreciation of furniture and office equipment is provided using the declining balance method based uponestimated useful lives at a rate of 25%.

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EXSHAW OIL CORP.



(b) Interest in joint operations:

Some of the Company’s oil and gas exploration and development activities are conducted jointly with others and,accordingly, the financial statements reflect only the Company’s proportionate interest in such activities.

(c) Cash and cash equivalents:

Cash is defined as cash and investments with a maturity of three months or less.

(d) Future income taxes:

The Company uses the asset and liability method of income taxes. Under this method, income tax liabilities andassets are recognized for the estimated tax consequences attributable to differences between the amounts reported inthe financial statements and their respective tax bases, using income tax rates substantively enacted at the balance sheetdate. The effect of change in rates on future income tax liabilities and assets is recognized in the period that the changeoccurs.

(e) Use of estimates:

The preparation of financial statements in accordance with Canadian generally accepted accounting principlesrequires management to make estimates and assumptions that affect the reported amounts of assets and liabilities anddisclosure of contingent assets and liabilities and the reported amounts of revenues and expenses during the reportingperiod. In particular, the amounts recorded for depletion of petroleum and natural gas properties and equipment, theasset retirement obligations, the valuation of undeveloped land, stock-based compensation and future income taxes arebased on estimates. The ceiling test is based on estimates of reserves, production rates, petroleum and natural gasprices, future costs and other relevant assumptions. Actual results could differ from these estimates.

(f) Stock-based compensation:

The Company applies the fair value method for valuing its stock-based compensation programs. Under thismethod, compensation costs attributable to all employee stock-based compensation programs are measured at their fairvalue at the grant and issuance date and expensed over the vesting period with a corresponding increase to contributedsurplus. Upon the exercise of the stock options and warrants, consideration received, together with the amountpreviously recognized in contributed surplus, is recorded as an increase to share capital.

(g) Asset retirement obligations:

The fair value of the liability for the Company’s asset retirement obligation is recorded in the period in which it isincurred, discounted to its present value using the Company’s credit adjusted risk-free interest rate and thecorresponding amount recognized by increasing the carrying amount of property, plant and equipment. The liabilityamount is increased each reporting period due to the passage of time and the amount of accretion is charged to earningsin the period.

Revisions to the estimated timing of cash flows or to the original estimated undiscounted cost could also result inan increase or decrease to the obligation. Actual costs incurred upon settlement of the retirement obligation are chargedagainst the obligation.

(h) Flow-through shares:

Flow-through shares are issued at a fixed price and the proceeds are used to fund qualifying explorationexpenditures within a defined period. The expenditures funded by flow-through arrangements are renounced toinvestors in accordance with tax legislation. Share capital is reduced and future tax liability is increased by the totalestimated future income tax costs of the renounced tax deductions in the period of renouncement.

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EXSHAW OIL CORP.



(i) Revenue recognition:

Revenue from the sale of petroleum and natural gas is recognized during the month when title passes to anexternal party.

3. Changes in accounting policies:

On January 1, 2008, the Company adopted the following new accounting standards issued by the CanadianInstitute of Chartered Accountants (the “CICA”). These standards had no impact on previously reported amounts forprior periods.

(i) Financial Instruments – Recognition and Measurement

Financial instruments are required to be measured at fair value on the balance sheet upon initial recognition of theinstrument. Measurement in subsequent periods depends on whether the financial instrument has been classified in oneof the following categories: held-for-trading; available-for-sale; held-to-maturity; loans and receivables, or otherfinancial liabilities as defined under the new standard.

Under adoption of these standards, cash and cash equivalents are designated as held-for-trading and are measuredat carrying value, which approximates fair value due to the short-term nature of these instruments. Accounts receivableand accrued revenues are designated as loans and receivables. Accounts payable and accrued liabilities and long-termdebt are designated as other liabilities. Risk management assets and liabilities being derivative financial instruments areclassified as held-for-trading.

Derivatives

At this time, the Company has not entered into any derivatives to manage the price risk attributable to the sale ofpetroleum and natural gas production. Refer to Note 8 for additional disclosure on the Company’s risk managementobjectives.

Embedded Derivatives

The Company has elected to recognize, as separate assets and liabilities, only those embedded derivatives inhybrid instruments issued, acquired or substantively modified after January 1, 2003. The Company has not identifiedany significant embedded derivatives which require separate recognition and measurement.

Effective Interest Method

Transaction costs attributable to the financial instruments classified as other than held-for-trading are included inthe recognized amount of the related financial instrument and expensed over the life of the resulting financialinstrument using the effective interest rate method. Prior to January 1, 2008, transaction costs were recorded asdeferred charges and recognized in net earnings on a straight-line basis over the life of the financial instrument. Onadoption, transaction costs are amortized using the effective interest rate method. The Company has determined that ithad no such items that would impact the financial statements for the year ended December 31, 2008.

(ii) Hedging

The new standard specifies the circumstances under which hedge accounting is permissible and how hedgeaccounting may be performed. On adoption of these standards, the Corporation did not have any agreements orcontracts to which hedge accounting would apply.

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EXSHAW OIL CORP.



(iii) Comprehensive Income

Comprehensive income is the change in shareholders’ equity during a period from transactions and other eventsfrom non-owner sources. This standard requires certain gains and losses that would otherwise be recorded as part of netearnings to be presented in “Other Comprehensive Income or Loss” until it is considered appropriate to recognize intonet earnings. The standard requires the presentation of comprehensive income, and its components in a separatefinancial statement. The Company has determined that it had no items that would affect comprehensive income, noraccumulated other comprehensive income as at and for the year ended December 31, 2008 and thereforecomprehensive income equals net income.

(iv) Equity

The Company adopted Section 3251, Equity, which establishes standards for the presentation of equity andchanges in equity during the reporting period. The adoption of this standard has not had a material impact upon theCompany’s financial statements.

(v) Financial Instruments – Disclosures and Presentation

On January 1, 2008, the Company also adopted CICA Handbook Section 3862, Financial Instruments –Disclosures, and Section 3863, Financial Instruments – Presentation. Section 3862 and 3863 establish standards forthe presentation and disclosure of information that enable users to evaluate the significance of financial instruments tothe entity’s financial position, and the nature and extent of risks arising from financial instruments and how the entitymanages these risks. The implementation of these standards did not impact the Company’s financial results; however,it did result in additional disclosure presented in Note 8.

(vi) Capital Disclosures

On January 1, 2008, the Company adopted CICA Handbook Section 1535, Capital Disclosures. This sectionestablishes standards for disclosing information about an entity’s capital and how it is managed. This section specifiesdisclosure about objectives, policies and processes for managing capital, quantitative data about what an entity regardsas capital, whether an entity has complied with all capital requirements, and if it has not complied, the consequences ofsuch non-compliance. The implementation of this standard did not impact the Company’s financial results; however, itdid result in additional disclosure presented in Note 8.



Canadian public entities will need to begin reporting under the IFRS by the first quarter of 2011 with appropriatecomparative data from the prior year. Under IFRS, there is significantly more disclosure required, specifically forquarterly reporting. Further, while IFRS uses a conceptual framework similar to Canadian GAAP, there are significantdifferences in accounting policy which must be addressed.

4. Property, plant and equipment:

December 31, 2008 December 31, 2007

Cost

AccumulatedDepletion andDepreciation

Net BookValue

Net BookValue

Petroleum and natural gas properties . . . . . . . . . . . . . . . . . . . . . $184,715 $30,350 $154,365 $135,314Plant and facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13,998 672 13,326 10,350Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 219 78 141 133

$198,932 $31,100 $167,832 $145,797

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General and administrative expenditures in the amount of $1,502,000 (2007 – $1,222,000) have been capitalizedand included as costs of petroleum and natural gas properties. Included in this amount are general and administrativeexpenses of $1,134,000 (2007 – $930,000) and non-cash related stock-based compensation of $276,000 (2007–$210,000). A future tax liability of $92,000 (2007 – $80,000) associated with the capitalized stock-based compensationhas also been capitalized.

The cost of unproven properties at December 31, 2008 in the amount of $23,134,000 (2007 – $28,755,000) hasbeen excluded from the depletion calculation. Future development costs related to proved reserves in the amount of$46,400,000 (2007 – $29,556,000) have been included in the depletion calculation.

At December 31, 2008, the Company applied a ceiling test to its petroleum and natural gas assets using expectedfuture market prices of:

Benchmark reference price forecast 2009 2010 2011 2012 2013

WTI (US$/bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55.00 76.50 88.45 100.80 108.25AECO (Cdn$/mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.00 8.05 8.20 9.00 9.75Exchange Rate (US$/Cdn$) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .82 .86 .90 .95 .95

The above prices have been adjusted in the ceiling test calculation to reflect Company-specific transportation andquality differentials. After 2013, the price forecast for WTI and AECO escalate at 2% per year to the end of the reservelife and the exchange rate remains constant at $0.95.

5. Long term debt:

The Company has a financing arrangement with a Canadian chartered bank for an extendible revolving term loanin the amount of $15 million in addition to a $5 million operating line. The interest rate varies based on the amountoutstanding. Security for the facility includes a general security agreement and a $200 million demand loan debenturesecured by a first floating charge over all assets. In May 2009, at the Company’s discretion, the facility is available ona non-revolving basis for one year at which time the facility would be due and payable. Alternatively, the facility maybe extended for a further 364-day period at the request of the Company and subject to approval by the bank. TheCompany has met all of the covenants required to maintain the facility.

At December 31, 2008, no amount of the loan was outstanding.

6. Asset retirement obligations:

The Company’s asset retirement obligations result from net ownership interests in petroleum and natural gasassets including well sites, gathering systems and processing facilities. The Company estimates the total undiscountedamount of cash flows required to settle its asset retirement obligations is approximately $4,984,000 (2007 –$3,346,000) (inflation adjusted) which will be incurred between 2008 and 2038. A credit-adjusted risk-free rate of 8%(2007 – 8%) and an inflation rate of 2% (2007 – 2%) were used to calculate the fair value of the asset retirementobligations.

The changes in the asset retirement obligation are as follows:

December 31 2008 2007

Balance, beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,100 $ 726Liabilities incurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 591 431Revisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148 (131)Accretion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98 74

Balance, end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,937 $1,100

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7. Share capital:

(a) Authorized:

Unlimited number of common shares

Unlimited number of preferred shares

(b) Common shares issued:

2008 2007

December 31Number of

Shares AmountNumber of

Shares Amount

Balance, beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49,400 146,444 43,500 $122,470For cash on flow-through shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,940 13,002 5,900 25,213Tax effect of flow-through share renunciation . . . . . . . . . . . . . . . . . . . . (6,303) — —Share issue costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (801) — (1,762)Tax effect on share issue costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 221 — 523

Balance, end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53,340 152,563 49,400 $146,444

(c) Flow-through shares:

On December 9, 2008, the Company issued 3,940,000 common shares on a flow-through basis at an issue price of$3.30 per share for gross proceeds of $13,002,000. Management and directors of the Company purchased 360,000 ofthese shares at $3.30 per share.

During the year ending December 31, 2008, Exshaw fulfilled its obligation of $10.2 million of capitalexpenditures related to the November 26, 2007 flow-through offering. As at December 31, 2008, the Companyestimates that it has an obligation in the amount of $13.0 million remaining from the December 9, 2008 offering whichmust be spent on qualifying exploration expenditures prior to December 31, 2009.

(d) Contributed surplus:

December 31 2008 2007

Balance, beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,352 $1,821Stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 584 531

Balance, end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,936 $2,352

(e) Stock options:

The Company has a stock option plan whereby directors, officers, employees and consultants are eligible to receiveoptions. Under the stock option plan, the Company may grant options for up to 10% of the outstanding common stock.The exercise price of each option equals the market price of the Company’s stock at grant date. Options vest 1/3 on eachof the first, second and third anniversaries from the date of grant and the maximum term is five years.

Options Outstanding Options Exercisable

NumberOutstanding


WeightedAverage

RemainingContractualLife (years)

NumberExercisable

AtDecember 31, 2008


Outstanding, December 31, 2007 . . . . . . . . . . . . . . . . 3,425,000 3.00 3.14 2,008,833 3.00Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 370,000 2.75 4.92 — —

Outstanding, December 31, 2008 . . . . . . . . . . . . . . . . 3,795,000 2.98 3.31 2,008,833 3.00

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The Company uses the fair value based method for the determination of all stock-based compensation costs. Thefair value of each employee option granted during the year was estimated on the date of grant using the Black-Scholesoption-pricing model. The Company determined the fair value for employee stock options using the minimum valuemethod. The assumptions used in the pricing model were a risk free interest rate of 2.26%, a volatility of nil, anexpected life of 5.0 years at the grant date and a $nil dividend rate, respectively. The weighted average fair value ofeach employee stock option issued during the year was $0.29 per option at the grant date. Stock-based compensationcosts in the amount of $583,911 have been recorded in the current year related to all of the issued stock options.

(f) Performance warrants:

The Company has a performance warrant plan whereby directors, officers, employees and consultants are eligibleto receive performance warrants. Under the performance warrant program, the Company may issue up to 5,775,000warrants.

The performance warrants are fully vested on issuance and are exercisable as follows:

Exercise PriceRemainingLife (Yr)

OutstandingDecember 31, 2007 Issued

OutstandingDecember 31, 2008

NumberExercisable

$3.50 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.95 1,002,454 122,038 1,124,492 1,124,492$4.50 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.95 1,002,454 122,038 1,124,492 1,124,492$5.50 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.95 1,002,454 122,038 1,124,492 1,124,492$6.50 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.95 1,002,454 122,038 1,124,492 1,124,492$7.50 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.95 1,002,454 122,038 1,124,492 1,124,492

The fair value of each warrant granted during the year was estimated on the date of grant using the Black-Scholesoption-pricing model. The Company determined fair value for employee warrants using the minimum value method.The assumptions used in the pricing model were a risk free interest rate of 1.64%, a volatility of nil, an expected life ofone year at the grant date and a $nil dividend rate, respectively. No stock-based compensation costs have been recordedin the current year related to the performance warrants.

8. Financial instruments:

The Company has exposure to the following risks from its use of financial instruments:

Š Credit risk

Š Liquidity risk

Š Market risk

Credit risk:

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument failsto meet its contractual obligations, and arises principally from the Company’s receivables from joint venture partnersand petroleum and natural gas marketers.

Receivables from petroleum and natural gas marketers are normally collected on the 25th day of the monthfollowing production. The Company’s policy to mitigate credit risk associated with these balances is to establishmarketing relationships with creditworthy purchasers. To date, no collection issues have been experienced by theCompany on these arrangements. Joint venture receivables are typically collected within one to three months of thejoint venture bill being issued to the partner. The Company attempts to mitigate the risk from joint venture receivablesby obtaining partner approval of significant capital expenditures prior to expenditure. However, the receivables arefrom participants in the petroleum and natural gas sector, and collection of the outstanding balances is dependent onindustry factors such as commodity prices and the risk of unsuccessful drilling. In addition, further risk exists with jointventure partners as disagreements occasionally arise that increases the potential for non-collection. The Company does

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not typically obtain collateral from petroleum and natural gas marketers or joint venture partners; however, theCompany does have the ability to withhold production from joint venture partners in the event of non-payment.

The Company monitors the age of and investigates issues behind its receivables that have been past due for over 60days. The Company’s accounts receivable balance at December 31, 2008 is approximately $4.1 million of which $4,600of this balance has been outstanding greater than 90 days. The Company is satisfied that these amounts are collectible.

The carrying amount of accounts receivable and cash and cash equivalents represents the maximum creditexposure. The Company does not have an allowance for doubtful accounts as at December 31, 2008 and 2007, nor wasit required to write-off any receivables during these years.

Liquidity risk:

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they come due. TheCompany prepares annual capital expenditure budgets which are regularly monitored and updated as considerednecessary. Further, the Company utilizes authorizations for expenditures on both operated and non-operated projects tofurther manage capital expenditures. To facilitate the capital expenditure program, the Company has a revolving reserve-based credit facility, as outlined in Note 3, which is reviewed at least annually by the lender. The Company also attemptsto match its payment cycle with collection of petroleum and natural gas revenues on the 25th of each month.

The Company’s accounts payable and accrued liabilities balance at December 31, 2008 is approximately $12.9million. It is the Company’s policy to pay suppliers within 90 days. These terms are consistent with industry standards.

Market risk:

The Company has the ability to utilize both financial derivatives and physical delivery sales contracts to managemarket risks. All such transactions must be approved by the Board of Directors.

Currency risk has no impact on the value of the financial assets and liabilities on the balance sheet atDecember 31, 2008. Changes in the U.S. to Canadian exchange rate, however, could influence future petroleum andnatural gas prices which impact the value of certain derivative contracts.

The Company is exposed to interest rate risk via fluctuations on its bank debt which bears a floating rate ofinterest. The Company had no interest rate swaps or financial contracts in place as at, or during, the year endedDecember 31, 2008.

Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes incommodity prices. The Company has not entered into any financial derivatives to mitigate commodity price risk at thispoint although it may in the future as its production increases.

Capital management:

The Company’s policy is to maintain a strong capital base so as to maintain investor, creditor and marketconfidence and to sustain the future development of the business. The Company considers its capital structure toinclude shareholders’ equity, bank dept and working capital. In order to maintain or adjust the capital structure, theCompany may, from time to time, issue shares and adjust its capital spending to manage current and projected debtlevels. The annual and updated budgets are approved by the Board of Directors.

The key measures that the Company utilizes in evaluating its capital structure are total debt to cash flow fromoperations (before changes in non-cash working capital) and the current credit available from its lenders in relation tothe Company’s budgeted capital program. At December 31, 2008 the Company had no debt outstanding and a workingcapital surplus of $2.5 million.

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The Company’s share capital is not subject to external restrictions; however, the bank debt facility is based onpetroleum and natural gas reserves and certain financial covenants (see Note 3). The Company has not paid or declaredany dividends since the date of incorporation, nor are any contemplated in the foreseeable future.

9. Income taxes:

The provision for income taxes in the financial statements differs from the result, which would have been obtainedby applying the combined federal and provincial tax rate to the Company’s earnings before income taxes. Thisdifference results from the following items:



Earnings before taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $8,366 $1,229

Combined federal and provincial tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29.5% 32.12%Computed “expected” income tax (recovery) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,468 $ 395Increase resulting from:

Effect of change in tax rate and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (495) (74)Stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92 103

Future income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,065 $ 424

The components of the Company’s future income tax liability/(asset) are as follows:

December 31, 2008 December 31, 2007

Future tax assets:Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (484) $ (275)Share issue costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,255) (1,485)Non-capital loss carry-forward . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,902) (576)

(3,641) (2,336)Future tax liabilities:

Property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,612 1,066

Net future tax liability (asset) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6,969 $(1,270)

At December 31, 2008, the Company had non-capital losses in the amount of $6.5 million which expire in 2027.

10. Supplemental cash flow information:



Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 625 $ (3,578)Prepaid expenses and deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (193) (825)Accounts payable and accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 574 12,030

Change in non-cash working capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,006 $ 7,627

Relating to:Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,137 $ (305)Investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (131) 7,932

Change in non-cash working capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,006 $ 7,627

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EXSHAW OIL CORP.



11. Commitments:

In the normal course of business, Exshaw is obligated to make future payments. The following obligationsrepresent commitments that are known and non-cancelable.

Payment due by year Total 2009 2010

Operating lease . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $454 $341 $113

As at December 31, 2008, the Company estimates that it has an obligation remaining in the amount of $13.0million from the December 9, 2008 flow-through share offering which must be spent on qualifying explorationexpenditures prior to December 31, 2009.

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Altia Energy Ltd.

Unaudited Financial StatementsDecember 31, 2009 – 3rd Qtr 2009/2010

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Altia Energy Ltd.

Unaudited Balance SheetAs at

December 31,2009

($000s)

March 31,2009

($000s)

AssetsCurrent assetsAccounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,813 1,908Prepaids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 168 223

1,981 2,131

Shareholder loan receivable (note 6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 286 284Properties and equipment (note 2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39,138 40,230

41,405 42,645

LiabilitiesCurrent liabilitiesAccounts payable and accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,192 3,515Bank debt (note 4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,903 2,993

7,095 6,508

Asset retirement obligation (note 3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 375 371

7,470 6,879

Shareholders’ EquityShare capital (note 6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41,309 41,309Contributed surplus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 525 296Deficit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (7,899) (5,839)

33,935 35,766

41,405 42,645


See accompanying notes to Financial Statements

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Altia Energy Ltd.

Unaudited Statement of Operations and DeficitFor the period ended December 31

Three months endedDecember 31

Nine months endedDecember 31

2009($000s)

2008($000s)

2009($000s)

2008($000s)

RevenuesPetroleum and natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,882 5,867 7,443 17,064Interest and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — (10) 2 8Royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (493) (1,250) (1,118) (3,631)

2,389 4,607 6,327 13,441

ExpensesOperating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 158 398 571 1,193Transportation and selling expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113 136 406 393General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 289 206 864 644Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 — 85 —Stock-based compensation (note 7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 199 8 228 49Depletion, depreciation and accretion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,768 3,072 6,233 7,962

2,561 3,820 8,386 10,241

Net income (loss) before taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (172) 787 (2,060) 3,200

TaxesFuture income tax recovery (note 5) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — —

Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (172) 787 (2,060) 3,200

Deficit– beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (7,727) (6,211) (5,839) (8,624)

Deficit– end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (7,899) (5,424) (7,899) (5,424)


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Altia Energy Ltd.

Unaudited Statement of Cash FlowsFor the period ended December 31



2009($000s)

2008($000s)

2009($000s)

2008($000s)

Operating activitiesNet income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (172) 787 (2,060) 3,200Items not affecting cash

Depletion, depreciation and accretion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,768 3,072 6,233 7,962Stock-based compensation (note 7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 199 8 228 49Shareholder loan interest (note 6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — (3) (2) (8)

Asset retirement expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — (41) —

Funds from operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,795 3,864 4,358 11,208Change in non-cash working capital (note 11) . . . . . . . . . . . . . . . . . . . . . . . . . . . . (577) (2,756) (262) (3,429)

1,218 1,108 4,096 7,779

Financing activitiesIncrease (decrease) in bank debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,579 5,916 1,910 5,916

1,579 5,916 1,910 5,916

Investing activitiesExpenditures on properties and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,591) (7,617) (5,095) (15,360)Disposition of properties and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — 509Change in non-cash working capital (note 11) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 794 (1,263) (911) (2,163)

(2,797) (8,880) (6,006) (17,014)

Decrease in cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — (1,856) — (3,319)Cash – Beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 1,856 — 3,319

Cash – End of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — —


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Notes to Unaudited Financial StatementsDecember 31, 2009


Altia Energy Ltd. was incorporated under the Business Corporations Act (Alberta) on June 12, 2003 and is currentlyinvolved in the exploration, development and production of petroleum and natural gas in Alberta and British Columbia.The financial statements have been prepared by management in accordance with generally accepted accounting principlesin Canada. The preparation of financial statements in conformity with generally accepted accounting principles requiresmanagement to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure ofcontingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expensesduring the period. Actual results could differ from these estimates. In the opinion of management, these financialstatements have been prepared within reasonable limits of materiality and within the framework of the significantaccounting policies summarized below. Among the more significant of these policies are the following:


The amounts recorded for depletion and depreciation of petroleum and natural gas properties and equipment, and theprovision for asset retirement obligation costs, are based on estimates. In addition, the ceiling test calculation is based onestimates of proved and probable reserves, production rates, gas prices, future costs and other relevant assumptions. Bytheir nature, those estimates are subject to measurement uncertainty, and the effect on the financial statements of changesin estimates in future periods could be material.

Cash and Cash Equivalents

Cash and cash equivalents consist of cash and highly liquid investments with an original less than 3 monthsmaturity. Cash and cash equivalents are stated at cost, which approximates market value.

Properties and equipment


The Company follows the full cost method of accounting for oil and gas activities whereby all costs associated withthe acquisition of, exploration for and development of oil and gas reserves are capitalized. Such costs include leaseacquisition costs, geological and geophysical expenditures, lease rentals on non-producing properties, costs of drillingboth productive and non-productive wells, equipment costs, and certain overhead expenditures related to exploration.

Gains or losses on the sale of properties and equipment are recognized only when crediting the proceeds tocapitalized costs would result in a change of 20 percent or more in the depletion rate.


Depletion of properties and equipment is provided using the unit-of-production method based on total estimatedproven petroleum and natural gas reserves, before royalties. Production and reserves of natural gas are converted toequivalent barrels of crude oil based on the energy equivalent ratio of six thousand cubic feet of natural gas to onebarrel of crude oil.

The depletion cost base includes total capitalized costs, less unimpaired costs of unproved properties andestimated future salvage values, plus provision for future development costs of proven undeveloped reserves.

Other fixed assets are recorded at cost upon acquisition and depreciated using a straight-line method over theestimated useful life of the asset.

c) Asset retirement obligation

The Company recognizes the estimated fair value of an asset retirement obligation (ARO) in the period in which itis incurred when a reasonable estimate of the fair value can be made. The fair value of the estimated ARO is recordedas a liability with a corresponding increase in the carrying value of the related asset. ARO obligations are initially

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Altia Energy Ltd.


measured at fair value and subsequently adjusted for the accretion of discount and any changes to the underlying cashflows. The capitalized amount is depleted on a unit-of-production basis over the life of the proved reserves.

d) Ceiling test

The Company applies an annual ceiling test as a test of impairment of its capitalized costs relating to its petroleumand natural gas properties. The cost centre is tested for recoverability by comparison to undiscounted estimated futurenet revenues (cash flows) from proved reserves using forecasted prices, plus the unimpaired cost of unprovedproperties. Should the ceiling test result in an excess of carrying value, the Company would then measure the amountof impairment by comparing the carrying amounts of petroleum and natural gas properties to an amount equal to theestimated net present value of future cash flows from proved plus probable reserves and the lower of cost and marketof unproved properties. A risk free interest rate would be used to arrive at the net present value of future cash flows.The carrying value of petroleum and natural gas properties in excess of the future cash flows would be recorded as apermanent impairment.

Future income taxes

The Company follows the liability method of accounting for income taxes. Under the liability method, temporarydifferences arising from the tax basis of an asset or liability and its carrying amount on the balance sheet are used tocalculate future income taxes or liabilities. Future income tax assets or liabilities are calculated using tax ratesanticipated to apply in the periods that the temporary differences are expected to reverse.

Stock based compensation plan and performance warrants

The Company has a stock-based compensation plan. The fair value of each option granted is estimated on the dateof grant and a provision for the costs is provided for as contributed surplus over the term of the option agreement. Theconsideration received by the Company on the exercise of share options is recorded as an increase to share capital,together with corresponding amounts previously recognized in contributed surplus. Forfeitures are accounted for asthey occur, which could result in recoveries of the compensation expense.

Revenue recognition

Revenue from the sale of natural gas, oil and natural gas liquids is recorded when title passes to an external party.

Joint ventures

Certain of the Company’s exploration, development and production activities are conducted jointly with others,and accordingly, the accounts reflect only the Company’s proportionate interest in such activities.

2 Properties and equipment

December 312009

($000s)

March 312009

($000s)

Properties and equipment, at cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75,972 70,857Fixed assets, at cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 155 155Less: Accumulated depletion & depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (36,989) (30,782)

39,138 40,230

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At December 31, 2009, oil and gas properties with a cost of $9.5 million (March 2009 – $10.0 million) relating toundeveloped properties have been excluded from the depletion and depreciation calculation. Future capital costsrequired to develop proved reserves in the amount of $12.7 million (March 2009 – $12.7 million) are included in thedepletion and depreciation calculation.

The Company capitalized general and administrative costs related to exploration of $0.4 million (March 2009 –$0.7 million).

3 Asset Retirement Obligation

December 312009

($000s)

March 312009

($000s)

Balance – Beginning of the period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 371 321Increase in obligations during the period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 33Settlement of obligations during the year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (41) (33)Change in estimate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 3Accretion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 47

Balance – End of the period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 375 371

The total future asset retirement obligation was estimated by management based on the Company’s net ownershipinterest in the wells, estimated costs to reclaim and abandon the wells, and the estimated timing of the costs to be incurredin future periods. At December 31, 2009 the estimated net present value of the asset retirement obligation was $0.38million (March 2009 – $0.37 million). The Company expects the undiscounted obligations of $1.05 million (March 2009– $0.98 million) to occur over the next 20 years with the majority of costs incurred in 17 years. A discount rate of 8% andan inflation rate of 2% was used to calculate the net present value of the asset retirement obligation.

4 Bank debt

On July 22, 2009, the Company renewed a business corporation agreement with the Alberta Treasury Branch tohave a revolving credit facility of $9,000,000. The Revolving Operating Demand Loan bears interest at the AlbertaTreasury Branch Prime Rate plus an interest rate ranging from 1.25 percent to 2.50 percent. At December 31, 2009 theRevolving Operating Demand Loan interest was calculated at the Alberta Treasury Branch Prime Rate plus 1.25percent. This facility is allowed to revolve and fluctuate at the Company’s discretion without fixed repayment termsand is subject to an annual review. As a result of the acquisition of Altia Energy Ltd. by Tourmaline Oil Corp. (see note13) the bank debt has been repaid in January 2010 and the facility loan has been cancelled.

The credit facility drawn at the Alberta Treasury Branch at December 31, 2009 is $4.9 million.

5 Future Income taxes

The estimated tax pool balances at December 31, 2009 are as follows:

($000s)Annual Rate of

Claim (%)

Undepreciated capital cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,901 20 – 100Canadian exploration expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26,350 100Canadian development expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,782 30Canadian oil and gas property expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,976 10ACRI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 781 100Non-capital loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,750 100

Total pools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50,540

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Altia Energy Ltd.


The provision for income taxes differs from the expected by applying the combined Canadian federal andprovincial corporate income tax rates as a result of the following:

December 312009

($000s)

December 312008

($000s)

Income (loss) before taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,060) 3,200Statutory combined federal and provincial income tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . 29.63% 29.38%Expected income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (610) 940Increase (decrease) resulting from:

Non-deductible Crown payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — —Non-deductible provincial royalty credits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — —Stock-based compensation expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67 14Changes in future income tax rates and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 505 (103)

Provision for (recovery of) future income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (38) 851Change in valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 (851)

— —

The components of future income taxes are as follows:

December 312009

($000s)

December 312008

($000s)

Property plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (375) (134)Asset retirement obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (94) (109)Share issue costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — —ACRI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (78) —Non-capital losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (937) (1,076)

(1,484) (1,319)Valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,484 1,319

Future income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — —

6 Share capital

Authorized

A) an unlimited number of Common Shares

B) an unlimited number of Preferred Shares

C) an unlimited number of Special Voting Shares

D) an unlimited number of Special Voting Shares Series 1

On November 15, 2007 the Company closed a private placement of 8,844,122 common shares at a price of $1.10per share for gross proceeds of $9.7 million. Concurrent with the private placement closing, the Company advancedloans to certain individuals in Management an aggregate amount of $0.27 million to purchase 246,787 common sharesat a price of $1.10. The loan will accrue interest at a rate equal to the quarterly prescribed interest rate of the CanadaRevenue Agency and will be repaid to the Company upon demand. As at December 31, 2009, advances plus accruedinterest totalling $.29 million were outstanding.

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Altia Energy Ltd.



Number of shares(000s)

Amount($000s)

Common SharesBalance – March 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32,810 31,336Issue of common shares

November 15, 2007 under private placement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,844 9,729November 15, 2007 under share purchase loan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 247 271Share issue costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (27)

Balance – March 31, 2008 and December 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41,901 41,309

7 Stock options

The Company has reserved 10% of its issued and outstanding common shares under a stock option plan enablingdirectors, officers, employees and consultants to purchase shares. Options are priced by the Board at the time of grant.Any consideration paid to the Company on exercise of stock options is credited to share capital.

As at December 31, 2009, the Company had outstanding options to purchase 4.0 million Common Shares at pricesranging from $1.00 to $1.50 per share. The current unallocated stock option balance is approximately 0.2 millionshares. The options vest over a period of three years from the date of grant. As a result of the acquisition of AltiaEnergy Ltd. by Tourmaline Oil Corp. (see note 13) all of the outstanding options vested.

The stock-based compensation resulted in a contributed surplus of $0.04 million (2008 – $0.05 million). Thisamount was determined using the Black-Scholes option pricing model, using risk-free interest rates ranging from3.185% to 4.38%, expected life of five years, expected average volatility factor of 0.01% to 61.89%, and no dividends.

A summary of the status of the Company’s stock option plan as of December 31, 2009 and changes during theperiod is presented below:

Options(000s)

Weighted averageexercise price

($)

Outstanding – March 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,667 1.00Granted – April 1, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 305 1.20

Outstanding – March 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,972 1.02Granted – November 15, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 985 1.10Granted – February 11, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 1.10

Balance – March 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,977 1.04Granted – June 27, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50 1.50

Balance – March 31, 2009 and December 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,027 1.05

Options exercisable (vested) – December 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,652 1.04

8 Performance warrants

The Company reserved 3.9 million common shares under a performance warrant agreement enabling directors,officers, employees and consultants to purchase shares. The performance warrants will not vest during the period ofSeptember 30, 2003 to September 30, 2010 unless the Fully-Diluted per Common Share amount results in a 25%annual compounded return for the Investors based on the issue price per Common Share of $1.00, such compoundedreturn to be calculated in respect of each Common Share subject to a minimum Fully-Diluted Threshold Value of $2.50per Common Share. If the Net Asset Value per Fully-Diluted Common Share exceeds $2.00 per Common Share,one-half of the Warrants outstanding will vest and become exercisable.

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As at December 31, 2009, the Company had outstanding performance warrants to acquire 3.8 million CommonShares at a price of $1.00 to $1.50. The current unallocated performance warrant balance is approximately 0.1 millionshares. At the date of grant the performance warrants were valued at nil using the minimal value Black-Scholes optionpricing model. As a result of the acquisition of Altia Energy Ltd. by Tourmaline Oil Corp. (see note 13) one-half of theoutstanding performance warrants vested.

The stock-based compensation resulted in a contributed surplus of $0.2 million (2008 – nil). This amount wasdetermined using the Black-Scholes option pricing model, using risk-free interest rates ranging from 3.185% to 4.38%,expected life of five years, expected average volatility factor of 0.01%, and no dividends.

A summary of the status of the Company’s performance warrant plan as of December 31, 2009 and changesduring the period is presented below:

PerformanceWarrants

(000s)

Weighted averageExercise price

($)

Outstanding – March 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,409 1.00Granted – April 23, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 365 1.20

Outstanding – March 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,774 1.02Granted – February 11, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 1.10

Outstanding – March 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,784 1.02Granted – June 27, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 1.50

Outstanding – March 31, 2009 and December 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . 3,809 1.02

Options exercisable (vested) – December 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,905 1.02

9 Commitments

As at December 31, 2009, the Company is committed to a long-term lease for office space of:

YearYear-to-date

($000s)

2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3322011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3322012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83

747

On November 18, 2008, the Company signed a 5 year contract with Westcoast Energy Inc. for 5 mmcf a day offirm eastbound transmission service commencing approximately November 1, 2009. The Company estimates theundiscounted cost over the 5 year contract at $1.2 million.

10 Financial Instruments

a) Fair values on financial assets and liabilities

Financial instruments of the Company consist manly of cash and short-term investments, deposits, receivables,payables and bank debt, all of which are included in these financial instruments.

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At December 31, 2009, the classification of financial instruments and the carrying amounts reported on thebalance sheet and their estimated fair values are as follows:

CarryingAmount($000s)

Fair Value($000s)

Accounts receivables and prepaids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,981 1,981Shareholder loan receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 286 286Accounts payable and bank debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (7,095) (7,095)

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,828) (4,828)

At March 31, 2009, the classification of financial instruments and the carrying amounts reported on the balancesheet and their estimated fair values are as follows:


Fair Value($000s)

Accounts receivables and prepaids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,131 2,131Shareholder loan receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 284 284Accounts payable and bank debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6,508) (6,508)

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,093) (4,093)

b) Credit risk

Substantially all of the accounts receivable are with joint venture partners, and oil and gas marketers and aresubject to normal industry credit risks. Receivables from joint venture partners are generally collected within one tothree months. The Company attempts to mitigate this risk by entering into transactions with long-standing andreputable organizations and by obtaining partner approval of significant capital expenditures and payment of cashadvances wherever possible. Further risk exists with joint venture partners as disagreements occasionally arise and mayincrease the potential for non-collection. Currently, there is no indication that amounts are non-collectible and as such,an allowance has not been set-up. Receivables related to oil and gas marketers are normally collected on the 25th dayof the month following production. To mitigate the risk of these receivables, the Company will predominately establishrelationships with marketers who have strong credit ratings and solid reputations. The Company has not experiencedany issues in collecting from its oil and gas marketers.

c) Interest rate risk

The Company is exposed to fluctuations in interest rates on its bank debt in response to changes in market interestrates. At December 31, 2009, the increase or decrease for each one percent change in interest rates amounts toapproximately $34 thousand in interest rate expense for the period ended December 31, 2009.

d) Capital structure

The Company’s objectives when managing capital are to (i) deploy capital to provide an appropriate return oninvestment to its shareholders; (ii) maintain financial flexibility in order to preserve its ability to meet financialobligations; and (iii) maintain a capital structure that provides financial flexibility to execute on strategic acquisitions.

The Company’s strategy is designed to maintain a flexible capital structure consistent with the objectives as statedabove and to respond to changes in economic conditions and the risk characteristics of the underlying petroleum andnatural gas assets.

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The Company considers its capital structure to include share capital, bank debt and working capital. In order tomaintain or adjust its capital structure, the Company may from time to time issue new shares, seek debt financing andadjust its capital spending to manage projected debt levels.

In order to facilitate the management of capital expenditures and projected net debt, the Company prepares annualbudgets which are updated as necessary depending upon varying factors including current and forecast natural gas andcrude oil prices, capital expenditures and general industry conditions. The annual budgets are approved by the Board ofDirectors.

At December 31, 2009, the Company had a negative working capital of $5.1 million which includes the bank debtof $4.9 million.

The Company’s share capital is not subject to external restrictions. The Company has not declared or paid anydividends since the incorporation date of June 12, 2003 and does not contemplate doing so in the foreseeable future.

11 Additional cash flow disclosure



2009($000s)

2008($000s)

2009($000s)

2008($000s)

Changes in non-cash working capitalAccounts receivable and prepaids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (261) (2,109) 150 (4,659)Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 478 (1,910) (1,323) (933)

217 (4,019) (1,173) (5,592)

Allocation of changes in non-cash working capitalOperating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (577) (2,756) (262) (3,429)Investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 794 (1,263) (911) (2,163)

217 (4,019) (1,173) (5,592)

12 Related party transactions

As of December 31, 2009, the Company had incurred drilling costs of $0.33 million (2008 – $1.0 million) to acompany that is partially owned by a director of Altia Energy Ltd. The Company has a shareholder loan receivable inthe amount of $0.29 million (2008 – $0.28) as described in Note 6. These transactions were recorded at the exchangeamount.

13 Subsequent event

On January 15, 2010, a Canadian Private E&P company, Tourmaline Oil Corp., purchased 100% of theoutstanding shares of Altia Energy Ltd. for a total consideration of $105 million comprised of $3 million in cash plus6.8 million Tourmaline common shares valued at $15 per share. The bank debt has been repaid in full and the AlbertaTreasury Bank facility loan has been cancelled.

FS-134

ALTIA ENERGY LTD.

Audited Financial StatementsMarch 31, 2009

FS-135

PricewaterhouseCoopers LLP Chartered Accountants111 5 Avenue SW, Suite 3100 Calgary, Alberta Canada T2P 5L3 Telephone +1 403 509 7500 Facsimile +1 403 781 1825

AUDITORS’ REPORT

To the Shareholder of Altia Energy Ltd.

We have audited the balance sheets of Altia Energy Ltd. as at March 31, 2009 and 2008 and the statement ofoperations and deficit and cash flows for the years then ended. These financial statements are the responsibility of thecompany’s management. Our responsibility is to express an opinion on these financial statements based on our audit.


In our opinion, these financial statements present fairly, in all material respects, the financial position of thecompany as at March 31, 2009 and 2008 and the results of its operations and its cash flows for the years endedMarch 31, 2009 and 2008 in accordance with Canadian generally accepted accounting principles.

Chartered AccountantsCalgary, Alberta

June 23, 2009

“PricewaterhouseCoopers” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership, or, as the context requires, thePricewaterhouseCoopers global network or other member firms of the network, each of which is a separate and independent legal entity.

FS-136

Altia Energy Ltd.

Balance SheetAs at March 31

2009($000s)

2008($000s)

AssetsCurrent assetsCash and short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 3,319Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,908 1,576Prepaids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 223 245

2,131 5,140

Shareholder loan receivable (note 6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 284 280Properties and equipment (note 2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40,230 33,666

42,645 39,086

LiabilitiesCurrent liabilitiesAccounts payable and accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,515 5,841Bank debt (note 4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,993 —

6,508 5,841

Asset retirement obligation (note 3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 371 321

6,879 6,162

Shareholders’ EquityShare capital (note 6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41,309 41,309Contributed surplus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 296 239Deficit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5,839) (8,624)

35,766 32,924

Commitments (note 9) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42,645 39,086


FS-137

Altia Energy Ltd.

Statement of Operations and DeficitFor the year ended March 31

2009($000s)

2008($000s)

RevenuesPetroleum and natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21,722 4,697Interest and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 113Royalties, net of credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,656) (717)

17,070 4,093ExpensesOperating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,540 1,375Transportation and selling expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 629 165General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 952 814Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 35Stock-based compensation (note 7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57 69Depletion, depreciation and accretion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11,082 2,961

14,285 5,419

Net income (loss) before taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,785 (1,326)

TaxesFuture income tax recovery (note 5) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — —

Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,785 (1,326)

Deficit– beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (8,624) (7,298)

Deficit– end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5,839) (8,624)


FS-138

Altia Energy Ltd.

Statement of Cash FlowsFor the period ended March 31

2009($000s)

2008($000s)

Operating activitiesNet income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,785 (1,326)Items not affecting cash

Depletion, depreciation and accretion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11,082 2,961Stock-based compensation (note 7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57 69Shareholder loan interest (note 6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4) (9)

Asset retirement expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (33) (75)

Funds from operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13,887 1,620Change in non-cash working capital (note 11) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,170) 624

12,717 2,244

Financing activitiesIssue of Common shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 9,702Increase (decrease) in bank debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,993 (3,688)

2,993 6,014

Investing activitiesExpenditures on properties and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (18,372) (13,575)Disposition of properties and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 809 5,100Change in non-cash working capital (note 11) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,466) 3,536

(19,029) (4,939)

Increase (decrease) in cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,319) 3,319Cash and short-term investments

– Beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,319 —

Cash and short-term investments– End of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 3,319


FS-139

Altia Energy Ltd.

Notes to Financial StatementsMarch 31, 2009


Altia Energy Ltd. was incorporated under the Business Corporations Act (Alberta) on June 12, 2003 and iscurrently involved in the exploration, development and production of petroleum and natural gas in Alberta and BritishColumbia. The financial statements have been prepared by management in accordance with generally acceptedaccounting principles in Canada. The preparation of financial statements in conformity with generally acceptedaccounting principles requires management to make estimates and assumptions that affect the reported amounts ofassets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and thereported amounts of revenues and expenses during the period. Actual results could differ from these estimates. In theopinion of management, these financial statements have been prepared within reasonable limits of materiality andwithin the framework of the significant accounting policies summarized below. Among the more significant of thesepolicies are the following:


The amounts recorded for depletion and depreciation of petroleum and natural gas properties and equipment, andthe provision for asset retirement obligation costs, are based on estimates. In addition, the ceiling test calculation isbased on estimates of proved and probable reserves, production rates, gas prices, future costs and other relevantassumptions. By their nature, those estimates are subject to measurement uncertainty, and the effect on the financialstatements of changes in estimates in future periods could be material.

Cash and Cash Equivalents

Cash and cash equivalents consist of cash and highly liquid investments with an original daily maturity. Cash andcash equivalents are stated at cost, which approximates market value.

Properties and equipment


The Company follows the full cost method of accounting for oil and gas activities whereby all costs associatedwith the acquisition of, exploration for and development of oil and gas reserves are capitalized. Such costs includelease acquisition costs, geological and geophysical expenditures, lease rentals on non-producing properties, costs ofdrilling both productive and non-productive wells, equipment costs, and certain overhead expenditures related toexploration.

Gains or losses on the sale of properties and equipment are recognized only when crediting the proceeds tocapitalized costs would result in a change of 20 percent or more in the depletion rate.


Depletion of properties and equipment is provided using the unit-of-production method based on total estimatedproven petroleum and natural gas reserves, before royalties. Production and reserves of natural gas are converted toequivalent barrels of crude oil based on the energy equivalent ratio of six thousand cubic feet of natural gas to onebarrel of crude oil.

The depletion cost base includes total capitalized costs, less unimpaired costs of unproved properties andestimated future salvage values, plus provision for future development costs of proven undeveloped reserves.

Other fixed assets are recorded at cost upon acquisition and depreciated using a straight-line method over theestimated useful life of the asset.

FS-140

Altia Energy Ltd.


c) Asset retirement obligation

The Company recognizes the estimated fair value of an asset retirement obligation (ARO) in the period in which itis incurred when a reasonable estimate of the fair value can be made. The fair value of the estimated ARO is recordedas a liability with a corresponding increase in the carrying value of the related asset. ARO obligations are initiallymeasured at fair value and subsequently adjusted for the accretion of discount and any changes to the underlying cashflows. The capitalized amount is depleted on a unit-of-production basis over the life of the proved reserves.

d) Ceiling test

The Company applies an annual ceiling test as a test of impairment of its capitalized costs relating to its petroleumand natural gas properties. The cost centre is tested for recoverability by comparison to undiscounted estimated futurenet revenues (cash flows) from proved reserves using forecasted prices, plus the unimpaired cost of unprovedproperties. Should the ceiling test result in an excess of carrying value, the Company would then measure the amountof impairment by comparing the carrying amounts of petroleum and natural gas properties to an amount equal to theestimated net present value of future cash flows from proved plus probable reserves and the lower of cost and marketof unproved properties. A risk free interest rate would be used to arrive at the net present value of future cash flows.The carrying value of petroleum and natural gas properties in excess of the future cash flows would be recorded as apermanent impairment.

Future income taxes

The Company follows the liability method of accounting for income taxes. Under the liability method, temporarydifferences arising from the tax basis of an asset or liability and its carrying amount on the balance sheet are used tocalculate future income taxes or liabilities. Future income tax assets or liabilities are calculated using tax ratesanticipated to apply in the periods that the temporary differences are expected to reverse.

Stock based compensation plan and performance warrants

The Company has a stock-based compensation plan. The fair value of each option granted is estimated on the dateof grant and a provision for the costs is provided for as contributed surplus over the term of the option agreement. Theconsideration received by the Company on the exercise of share options is recorded as an increase to share capital,together with corresponding amounts previously recognized in contributed surplus. Forfeitures are accounted for asthey occur, which could result in recoveries of the compensation expense.

Revenue recognition

Revenue from the sale of natural gas, oil and natural gas liquids is recorded when title passes to an external party.

Joint ventures

Certain of the Company’s exploration, development and production activities are conducted jointly with others,and accordingly, the accounts reflect only the Company’s proportionate interest in such activities.

Section 1506 Accounting Changes

Section 1506 provides expanded disclosures for changes in accounting policies, accounting estimates andcorrections of errors. Under the new standard, accounting changes should be applied retrospectively unless otherwisepermitted or where impracticable to determine. As well, voluntary changes in accounting policy are made only whenrequired by a primary source of GAAP or the change results in more relevant and reliable information.

FS-141

Altia Energy Ltd.



Section 3860 Financial Instruments – Disclosure and Presentation

On April 1, 2008, the Company adopted the new CICA standards, Section 3860 “Financial Instruments –Disclosures and Presentation”. The new disclosure standard increases the emphasis on the risks associated with bothrecognized and unrecognized financial instruments and how those risks are managed. The new presentation standardcarries forward the former presentation requirements. This will not impact the Company’s financial statements.

On October 2, 2008, the Accounting Standards Board decided that private enterprises will not be required to applythe following financial instrument standard sections: 1530 “Comprehensive Income,” 3855 “Financial Instruments –Recognition and Measurement,” 3862 “Financial Instruments – Disclosures,” 3863 “Financial Instruments –Presentation,” 3865 “Hedges,” and 3251 “Euity.” As the Company is a private enterprise, the Company has chosen notto adopt these financial instrument standards.


Section 1535 Capital Disclosures

On April 1, 2008, the Company adopted CICA standards, Section 1535 “Capital Disclosures,” which will requirecompanies to disclose their objectives, policies and processes for managing capital. In addition, disclosures are toinclude whether companies have complied with externally imposed capital requirements.

Future Changes in accounting policies

International Financial Reporting Standards

In January 2006, the CICA Accounting Standards Board (“AcSB”) adopted a strategic plan for the direction ofaccounting standards in Canada. As part of the plan, accounting standards in Canada for public companies are expectedto converge with International Financial Reporting Standards (“IFRS”) by the beginning of 2011. In May 2009, AcSBreleased an exposure draft of Generally Accepted Accounting Principles (GAAP) for Private Enterprises. Privatecompanies will have a choice of reporting in accordance with Canadian GAAP by adopting either the same set ofaccounting standards as public companies (IFRS) or the proposed standards for private companies (Canadian GAAPfor private enterprises). The Company is currently reviewing the requirements of IFRS and Canadian GAAP for privateenterprises and expects to adopt one of the new standards by the applicable dates.

2 Properties and equipment

2009($000s)

2008($000s)

Properties and equipment, at cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70,857 53,260Fixed assets, at cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 155 153Less: Accumulated depletion & depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (30,782) (19,747)

40,230 33,666

At March 31, 2009, oil and gas properties with a cost of $10.0 million (2008 – $7.0 million) relating toundeveloped properties have been excluded from the depletion and depreciation calculation. Future capital costsrequired to develop proved reserves in the amount of $12.7 million (2008 – $0.7 million) are included in the depletionand depreciation calculation.

The Company capitalized general and administrative costs related to exploration of $0.7 million (2008 – $0.7million).

As a result of the ceiling test calculations at March 31, 2009, the Company was not required to record a write-down.

FS-142

Altia Energy Ltd.


The Company calculated its year-end ceiling test using the pricing forecast of its independent reservoir engineers.The forecasted future prices used in the ceiling test evaluation of the Company’s proved reserves were as follows:

2009 2010 2011 2012 2013% IncreaseTo 2019

AECO-C ($Cdn / MMBTU) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.70 5.93 6.42 7.12 7.50 2.0%

3 Asset Retirement Obligation

2009($000s)

2008($000s)

Balance – Beginning of the period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 321 137Increase in obligations during the period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 81Settlement of obligations during the year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (33) (75)Change in estimate due to sale of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — (83)Change in estimate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 209Accretion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 52

Balance – End of the period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 371 321

The total future asset retirement obligation was estimated by management based on the Company’s net ownershipinterest in the wells, estimated costs to reclaim and abandon the wells, and the estimated timing of the costs to beincurred in future periods. At March 31, 2009 the estimated net present value of the asset retirement obligation was$0.37 million (2008 – $0.32 million). The Company expects the undiscounted obligations of $0.98 million (2008 –$0.91 million) to occur over the next 20 years with the majority of costs incurred in 17 years. A discount rate of 8%and an inflation rate of 2% was used to calculate the net present value of the asset retirement obligation.

4 Bank debt

On November 1, 2008, the Company signed a business corporation agreement with the Alberta Treasury Branchto have the revolving credit facility increased to $9,000,000. The Revolving Operating Demand Loan bears interest atthe Alberta Treasury Branch Prime Rate plus 0.25 percent. This facility is allowed to revolve and fluctuate at theCompany’s discretion without fixed repayment terms and is subject to an annual review. The next review is scheduledfor June 30, 2009.

The credit facility drawn at the Alberta Treasury Branch at March 31, 2009 is $3.0 million.

5 Future Income taxes

The estimated tax pool balances at March 31, 2009 are as follows:

($000s)Annual Rate of

Claim (%)

Undepreciated capital cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,651 20 – 100Canadian exploration expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22,473 100Canadian development expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,148 30Canadian oil and gas property expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,808 10ACRI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,177 100Non-capital loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,750 100

Total pools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46,007

FS-143

Altia Energy Ltd.


The provision for income taxes differs from the expected by applying the combined Canadian federal andprovincial corporate income tax rates as a result of the following:

2009($000s)

2008($000s)

Income (loss) before taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,785 (1,326)Statutory combined federal and provincial income tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30.52% 31.59%Expected income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 850 (419)Increase (decrease) resulting from:

Non-deductible Crown payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — —Non-deductible provincial royalty credits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 62Stock-based compensation expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 22Changes in future income tax rates and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (143) 262

Provision for (recovery of) future income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 723 (73)Change in valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (723) 73

— —

The components of future income taxes are as follows:

2009($000s)

2008($000s)

Property plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (256) (2020)Asset retirement obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (93) (87)Share issue costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — (63)ACRI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (118) —Non-capital losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (980)

(1,447) (2,170)Valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,447 2,170

Future income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — —

6 Share capital

Authorized

A) an unlimited number of Common Shares

B) an unlimited number of Preferred Shares

C) an unlimited number of Special Voting Shares

D) an unlimited number of Special Voting Shares Series 1

On November 15, 2007 the Company closed a private placement of 8,844,122 common shares at a price of $1.10per share for gross proceeds of $9.7 million. Concurrent with the private placement closing, the Company advancedloans to certain individuals in Management an aggregate amount of $0.27 million to purchase 246,787 common sharesat a price of $1.10. The loan will accrue interest at a rate equal to the quarterly prescribed interest rate of the CanadaRevenue Agency and will be repaid to the Company upon demand. As at March 31, 2009, advances plus accruedinterest of $0.28 million were outstanding.

FS-144

Altia Energy Ltd.



Number of shares(000s)

Amount($000s)

Common SharesBalance – March 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32,810 31,336Issue of common shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

November 15, 2007 under private placement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,844 9,729November 15, 2007 under share purchase loan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 247 271Share issue costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (27)

Balance – March 31, 2008 and March 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41,901 41,309

7 Stock options

The Company has reserved 10% of its issued and outstanding common shares under a stock option plan enablingdirectors, officers, employees and consultants to purchase shares. Options are priced by the Board at the time of grant.Any consideration paid to the Company on exercise of stock options is credited to share capital.

As at March 31, 2009, the Company had outstanding options to purchase 4.0 million Common Shares at pricesranging from $1.00 to $1.50 per share. The current unallocated stock option balance is approximately 0.2 millionshares. The options vest over a period of three years from the date of grant.

The stock-based compensation resulted in a contributed surplus of $0.06 million (2008 – $0.07 million). Thisamount was determined using the Black-Scholes option pricing model, using risk-free interest rates ranging from3.185 % to 4.38%, expected life of five years, expected average volatility factor of 0.01%, and no dividends.

A summary of the status of the Company’s stock option plan as of March 31, 2009 and changes during the periodis presented below:

Options(000s)

Weighted averageexercise price

($)

Outstanding – March 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,667 1.00Granted – April 1, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 305 1.20

Outstanding – March 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,972 1.02Granted – November 15, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 985 1.10Granted – February 11, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 1.10

Balance – March 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,977 1.04Granted – June 27, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50 1.50

Balance – March 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,027 1.05

Options exercisable (vested) – March 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,206 1.02

8 Performance warrants

The Company reserved 3.9 million common shares under a performance warrant agreement enabling directors,officers, employees and consultants to purchase shares. The performance warrants will not vest during the period ofSeptember 30, 2003 to September 30, 2010 unless the Company meets certain defined performance targets.

As at March 31, 2009, the Company had outstanding performance warrants to acquire 3.8 million Common Sharesat a price of $1.00 to $1.50. The current unallocated performance warrant balance is approximately 0.1 million shares.No performance warrants were vested in the period and no value was attributed to the performance warrants as thecriteria for valuation could not be determined.

FS-145

Altia Energy Ltd.


A summary of the status of the Company’s performance warrant plan as of March 31, 2009 and changes duringthe period is presented below:

PerformanceWarrants

(000s)

Weighted averageExercise price

($)

Outstanding – March 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,409 1.00Granted – April 23, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 365 1.20

Outstanding – March 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,774 1.02Granted – February 11, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 1.10

Outstanding – March 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,784 1.02Granted – June 27, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 1.50

Outstanding – March 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,809 1.02

Options exercisable (vested) – March 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — —

9 Commitments

As at March 31, 2009, the Company is committed to a long-term lease for office space of:

YearYear-to-date

($000s)

2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2492010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3322011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3322012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83

996

On November 18, 2008, the Company signed a 5 year contract with Westcoast Energy Inc. for 5 mmcf a day offirm eastbound transmission service commencing approximately November 1, 2009. At March 31, 2009, the fees havenot yet been established. The Company estimates the undiscounted cost over the 5 year contract at $1.2 million.

10 Financial Instruments


Financial instruments of the Company consist manly of cash and short-term investments, deposits, receivables,payables and bank debt, all of which are included in these financial instruments.



Fair Value($000s)

Cash and short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — —Accounts receivables and prepaids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,131 2,131Shareholder loan receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 284 284Accounts payable and bank debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6,508) (6,508)

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,093) (4,093)

FS-146

Altia Energy Ltd.




Fair Value($000s)

Cash and short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,319 3,319Accounts receivables and prepaids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,821 1,821Shareholder loan receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 280 280Accounts payable and bank debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5,841) (5,841)

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (421) (421)

b) Credit risk

Substantially all of the accounts receivable are with joint venture partners, and oil and gas marketers and aresubject to normal industry credit risks. Receivables from joint venture partners are generally collected within one tothree months. The Company attempts to mitigate this risk by entering into transactions with long-standing andreputable organizations and by obtaining partner approval of significant capital expenditures and payment of cashadvances wherever possible. Further risk exists with joint venture partners as disagreements occasionally arise and mayincrease the potential for non-collection. Currently, there is no indication that amounts are non-collectible and as such,an allowance has not been set-up. Receivables related to oil and gas marketers are normally collected on the 25th day ofthe month following production. To mitigate the risk of these receivables, the Company will predominately establishrelationships with marketers who have strong credit ratings and solid reputations. The Company has not experiencedany issues in collecting from its oil and gas marketers.


The Company is exposed to fluctuations in interest rates on its bank debt in response to changes in market interestrates. At March 31, 2009, the increase or decrease for each one percent change in interest rates amounts toapproximately $7 thousand in interest rate expense for the year ended March 31, 2009.


The Company’s objectives when managing capital are to (i) deploy capital to provide an appropriate return oninvestment to its shareholders; (ii) maintain financial flexibility in order to preserve its ability to meet financialobligations; and (iii) maintain a capital structure that provides financial flexibility to execute on strategic acquisitions.

The Company’s strategy is designed to maintain a flexible capital structure consistent with the objectives as statedabove and to respond to changes in economic conditions and the risk characteristics of the underlying petroleum andnatural gas assets.

The Company considers its capital structure to include share capital, bank debt and working capital. In order tomaintain or adjust its capital structure, the Company may from time to time issue new shares, seek debt financing andadjust its capital spending to manage projected debt levels.

In order to facilitate the management of capital expenditures and projected net debt, the Company prepares annualbudgets which are updated as necessary depending upon varying factors including current and forecast natural gas andcrude oil prices, capital expenditures and general industry conditions. The annual budgets are approved by the Board ofDirectors.

FS-147

Altia Energy Ltd.


At March 31, 2009, the Company had a negative working capital of $4.4 million which includes the bank debt of$3 million.

The Company’s share capital is not subject to external restrictions. The Company has not declared or paid anydividends since the incorporation date of June 12, 2003 and does not contemplate doing so in the foreseeable future.

11 Additional cash flow disclosure

2009($000s)

2008($000s)

Changes in non-cash working capitalAccounts receivable and prepaids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (310) 843Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,326) 3,317

(2,636) 4,160

Allocation of changes in non-cash working capitalOperating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,170) 624Investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,466) 3,536

(2,636) 4,160

12 Related party transactions

As of March 31, 2009, the Company had paid drilling costs of $1.0 million (2008 – $3.2 million) to a companythat is partially owned by a director of Altia Energy Ltd. The Company has a shareholder loan receivable in the amountof $0.28 million (2008 – $0.28) as described in Note 6. These transactions were recorded at the exchange amount.

FS-148

Schedules of Revenue, Royalties and Operating Expenses

Talisman Energy Inc.Greater Hinton Properties

Three Months Ended March 31, 2010 and 2009 andEach of the Years in the Two Year Period Ended December 31, 2009

FS-149

AUDITORS’ REPORT

To the Board of Directors ofTalisman Energy Inc.

At the request of Talisman Energy Inc., we have audited the Schedule of Revenue, Royalties and OperatingExpenses of the Greater Hinton Properties, as described in Note 1 to the Schedule, for the years ended December 31,2009 and 2008. This financial information is the responsibility of management. Our responsibility is to express anopinion on this financial information based on our audits.

We conducted our audits in accordance with the Canadian generally accepted auditing standards. Those standardsrequire that we plan and perform an audit to obtain reasonable assurance whether the financial information is free ofmaterial misstatements. An audit includes examining, on a test basis, evidence supporting the amounts and disclosuresin the financial information. An audit also includes assessing the accounting principles used and significant estimatesmade by management, as well as evaluating the overall financial information presentation.

In our opinion, the Schedules of Revenues, Royalties and Operating Expenses present fairly, in all materialrespects, the revenues, royalties and operating expenses of the Properties for the years ended December 31, 2009 and2008, in accordance with Canadian generally accepted accounting principles.

Calgary, CanadaJuly 23, 2010 Chartered Accountants

FS-150

Greater Hinton Properties

SCHEDULES OF REVENUE, ROYALTIESAND OPERATING EXPENSES

[in thousands of dollars]

Three months endedMarch 31

Year endedDecember 31

2010 2009 2009 2008

[unaudited] [audited] [audited]

Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12,565 10,072 36,149 43,820Royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,602) (2,434) (5,995) (4,106)

10,963 7,638 30,154 39,714Operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,322) (2,124) (7,565) (5,834)

Net operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,641 5,514 22,589 33,880

See accompanying notes to schedule

FS-151


NOTES TO SCHEDULES OF REVENUE, ROYALTIES AND OPERATING EXPENSESThree months ended March 31, 2010 and 2009 (Unaudited) and

Years ended December 31, 2009 and 2008


The Schedules of Revenue, Royalties and Operating Expenses include information relating to the operations ofcertain oil and gas properties (referred to as the Greater Hinton Properties) as listed in the Purchase and Sale agreementbetween Talisman Energy Inc. and Tourmaline Oil Corp.

The schedules, prepared from records supplied by Talisman, include only revenue, royalties and operatingexpenses directly related to the Greater Hinton Properties. The schedules do not include any provision for thedepletion, depreciation and amortization, asset retirement costs, future capital costs, impairment of unevaluatedproperties, foreign exchange gain (loss), administrative costs and income taxes for the Greater Hinton Properties, sincethe Greater Hinton Properties form only a part of the consolidated operations of Talisman.


Joint operations

Substantially all of the Greater Hinton Properties are operated through joint ventures. The schedules reflect onlyTalisman’s proportionate interest in the properties.

Revenue recognition

Revenue is recorded when the product is delivered and the title passes to an external party.

Royalties

Royalties are recorded at the time the product is produced and sold. Royalties are calculated in accordance withthe applicable regulations and/or the terms of individual royalty agreements.

Operating expenses

Operating expenses include amounts incurred on extraction of product to the surface, gathering, field processing,treating, compression and transportation to the point of sale.

FS-152

INDEX TO MANAGEMENT’S DISCUSSION AND ANALYSIS FOR CERTAIN BUSINESSACQUISITIONS

Page

Management’s discussion and analysis of the results of operations for the assets acquired pursuant to theAlberta Deep Basin Acquisition for the years ended December 31, 2008 and 2007 and for the three monthsended March 31, 2009 and 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . MDA-2

Management’s discussion and analysis of the results of operations for the assets acquired pursuant to theWild River Acquisition for the years ended December 31, 2008 and 2007 and for the six months endedJune 30, 2009 and 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . MDA-3

Management’s discussion and analysis of financial condition and results of operations for Exshaw for theperiods ended September 30, 2009 and September 30, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . MDA-4

Management’s discussion and analysis of financial condition and results of operations for Exshaw for theyears ended December 31, 2008 and December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . MDA-10

Management’s discussion and analysis of financial condition and results of operations for Altia for theperiods ended December 31, 2009 and December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . MDA-18

Management’s discussion and analysis of financial condition and results of operations for Altia for the yearsended March 31, 2009 and March 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . MDA-27

Management’s discussion and analysis of the results of operations for the assets acquired pursuant to theGreater Hinton Acquisition for the years ended December 31, 2009 and 2008 and for the three monthsended March 31, 2010 and 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . MDA-37

MDA-1


Management’s Discussion and AnalysisFor the years ended December 31, 2008 and 2007 and for the three months ended March 31, 2009 and 2008

The following management’s discussion and analysis of the results of operations should be read in conjunctionwith the unaudited schedules of revenues, royalties and operating expenses of the Alberta Deep Basin Properties for thethree months ended March 31, 2009 and 2008, and year ended December 31, 2007 and the audited schedule ofrevenues, royalties and operating expenses and the notes thereto for the year ended December 31, 2008 included in thisprospectus. This management’s discussion and analysis is dated November 15, 2010.

The financial information contained herein has been prepared in accordance with Canadian generally acceptedaccounting principles (“GAAP”). All dollar amounts are expressed in Canadian currency, unless otherwise noted.

PRODUCTION

The Alberta Deep Basin properties produced 894,909 Boe in 2008 (2007 – 863,636 Boe), averaging 2,452 Boe/din 2008 compared to an average rate of 2,366 Boe/d during 2007. The daily production rate for the three months endedMarch 31, 2009 averaged 1,791 Boe/d as compared to 2,780 Boe/d for the three months ended March 31, 2008.

REVENUES

Revenues for the year ended December 31, 2008 of $42.1 million increased from $30.5 million for 2007, due toimprovements in market prices for natural gas. Revenues fell from $11.0 million for the three months ended March 31,2008 to $4.2 million for the three months ended March 31, 2009 reflecting decreased production and weakened naturalgas prices.

ROYALTIES

For the year ended December 31, 2008, the average effective royalty rate was 18.1%, compared to 24.8% for2007. For the three months ended March 31, 2009 the average effective royalty rate was 27.5% compared to 13.7% forthe three months ended March 31, 2008.

OPERATING EXPENSES

Operating expenses for the year ended December 31, 2008 were $3.39/Boe ($3.0 million) compared to $2.21/Boe($1.9 million) for the year ended December 31, 2007 due to higher processing fees at Musreau. Similarly, operatingexpenses for the three months ended March 31, 2009 increased to $4.45/Boe ($0.7 million) compared to $2.98/Boe($0.7 million) for the same period in 2008.

NET OPERATING INCOME

Net operating income grew to $31.5 million in 2008 from $21.0 million in 2007. The increase was due toincreases in market prices for natural gas, offset partially by increases in operating expenses. Net operating income fellto $2.3 million for the three months ending March 31, 2009 compared to $8.7 million for the same period in the prioryear as market prices weakened and production volumes decreased.

MDA-2


Management’s Discussion and AnalysisFor the years ended December 31, 2008 and 2007 and for the six months ended June 30, 2009 and 2008

The following management’s discussion and analysis of the results of operations should be read in conjunctionwith the unaudited schedule of revenues, royalties and operating expenses for the six months ended June 30, 2009 and2008 and the audited schedule of revenues, royalties and operating expenses and the notes thereto of the Wild River,Harley, Olsen and Sundance properties for the years ended December 31, 2008 and 2007 included in this prospectus.This management’s discussion and analysis is dated November 15, 2010.


PRODUCTION

The Wild River, Harley, Olsen and Sundance properties produced 1,070,233 Boe in 2008 (2007 – 1,012,355 Boe),averaging 2,924 Boe/d in 2008 compared to an average rate of 2,774 Boe/d during 2007. The daily production rate forthe six months ended June 30, 2009 averaged 2,349 Boe/d as compared to 3,108 Boe/d for the six months endedJune 30, 2008.

REVENUE

Revenues for the year ended December 31, 2008 were $60.3 million compared to $45.7 million for 2007 asmarket prices for natural gas increased. Revenues fell from $32.5 million for the six months ended June 30, 2008 to$13.8 million for the six months ended June 30, 2009 as production decreased and natural gas prices subsequentlyweakened.

ROYALTIES

For the year ended December 31, 2008, the average effective royalty rate was 10.4%, compared to 9.7% for 2007.For the six months ended June 30, 2009 the average effective royalty rate was 7.7% compared to 9.9% for the sixmonths ended June 30, 2008.

OPERATING EXPENSES

Operating expenses for the year ended December 31, 2008 of $10.72/Boe ($11.5 million) increased slightly over2007 operating expenses of $10.04/Boe ($10.2 million). Operating expenses averaged $10.65/Boe ($4.5 million) forthe six months ended June 30, 2009 compared to $11.44/Boe ($6.4 million) for the same period in 2008.


Market prices for natural gas improved year over year leading to increases in net operating income to$42.6 million for 2008 from $31.1 million in 2007. Revenue increases were partially offset by increases in royaltiesand operating expenses. For the six months ended June 30, 2009 net operating income decreased to $8.2 million from$22.9 million for the same period in the prior year as both production and product prices decreased.

MDA-3

Exshaw Oil Corp.

MANAGEMENT’S DISCUSSION AND ANALYSISfor the Three and Nine Months ended September 30, 2009

The following Management’s Discussion and Analysis (“Exshaw Quarterly MD&A”) of financial results asprovided by the management of Exshaw Oil Corp. (“Exshaw”) should be read in conjunction with the unauditedinterim financial statements of Exshaw and selected notes for the three and nine month periods endedSeptember 30, 2009 and the audited financial statements and management’s discussion and analysis of Exshaw for theyear ended December 31, 2008 and comparative information therein included in this prospectus. This commentary isbased on information available as at December 8, 2009.

The information contained herein contains forward-looking statements and assumptions, such as those relating toresults of operations and financial condition, capital spending, financing sources, commodity prices and costs ofproduction. By their nature, forward-looking statements are subject to numerous risks and uncertainties that couldsignificantly affect anticipated results in the future and, accordingly, actual results may differ materially from thosepredicted. Readers are cautioned that the assumptions used in the preparation of such information, although consideredreasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed onforward-looking statements.

All financial results are reported in Canadian dollars and production numbers are stated before Crown or lessorroyalties. Natural gas volumes are converted to barrels of oil equivalent (Boe) on the basis of six thousand cubic feet(Mcf) of gas to one barrel (Bbl) of oil.

Business

Exshaw is an oil and gas company engaged in the exploration, development and production of oil and natural gasin Western Canada.

Production



Crude Oil (Bbls/d) . . . . . . . . . . . . . . . . . . . 670 433 682 460NGLs (Bbls/d) . . . . . . . . . . . . . . . . . . . . . . 70 104 68 81Natural Gas (Mcf/d) . . . . . . . . . . . . . . . . . . 10,307 11,674 10,651 9,960

Boe/d (6:1) . . . . . . . . . . . . . . . . . . . . . . . . . 2,458 2,483 2,525 2,201

% natural gas production . . . . . . . . . . . . . . 70 78 70 75

Average production for the current quarter decreased by 1% to 2,458 Boe/d compared to the third quarter of 2008.

Natural gas sales volumes averaged 10,307 Mcf/d during the three months ended September 30, 2009 compared to11,674 Mcf/d for the same period of 2008, a 12% decrease, due to natural declines. On a year-to-date basis for the firstnine months of 2009, natural gas production increased 7% over the comparable period in 2008 due to productionincreases in Spirit River and Elmworth.

Crude oil and natural gas liquids (“NGL”) sales volumes averaged 740 Boe/d for the three months endedSeptember 30, 2009, a 38% increase over the third quarter of 2008. The increase was due to higher oil production inSpirit River. Liquid production increased by 39% for the first nine months of 2009 compared to 2008. The increaseswere also due to higher production in Spirit River.

MDA-4

Commodity Pricing



Natural Gas ($/Mcf) . . . . . . . . . . . . . . . . . . 3.13 8.22 4.08 9.26Crude Oil ($/Bbl) . . . . . . . . . . . . . . . . . . . . 69.06 115.65 60.44 110.48NGL ($/Bbl) . . . . . . . . . . . . . . . . . . . . . . . . 48.66 122.82 49.11 114.24

Average price ($/Boe) . . . . . . . . . . . . . . . . 33.33 63.98 34.85 69.21

Overall prices received by Exshaw for the three month period ended September 30, 2009, decreased by 48% on anaverage $/Boe basis compared to the third quarter of 2008. Natural gas was 62% lower, crude oil was 40% lower andNGL were 60% lower. The overall average unit price received by Exshaw in the third quarter of 2009 was lower due tolower commodity prices. Prices also decreased by 50% for the nine month period ended September 30, 2009 comparedto 2008. Natural gas was 56% lower, crude oil was 45% lower and NGL were 57% lower, respectively. Exshaw’sprices were reflective of the overall market because Exshaw had not entered into any hedges.

Crude Oil and Gas Sales



$ 000 % $ 000 % $ 000 % $ 000 %Natural Gas . . . . . . . . . . . . . . . . . . . . . . 2,967 39 8,834 60 11,860 49 25,273 61Crude Oil . . . . . . . . . . . . . . . . . . . . . . . . 4,255 57 4,610 32 11,256 47 13,935 33NGL . . . . . . . . . . . . . . . . . . . . . . . . . . . 314 4 1,169 8 909 4 2,537 6

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,536 100 14,613 100 24,025 100 41,745 100

Total oil and gas sales revenues in the third quarter of 2009 were $7.5 million compared to $14.6 million for thesame quarter of 2008 primarily due to lower product prices. Year-to-date sales revenues for the first nine months of2009 were $24 million, compared to $41.7 million in 2008. The decreases in revenue were due to lower prices whichwere partially offset by higher production.

Royalties


($000) September 30, 2009 September 30, 2008 September 30, 2009 September 30, 2008

Crown royalties . . . . . . . . . . . . . . . . . . . . . 1,011 3,071 3,278 7,405Other royalties . . . . . . . . . . . . . . . . . . . . . . 105 894 515 1,895

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,116 3,965 3,793 9,300

The total royalty expense for the three and nine month periods ended September 30, 2009 decreased compared tothe corresponding periods in 2008 primarily due to lower oil and gas sales. The overall effective royalty rate in 2009was lower than the corresponding periods in 2008 due to lower Alberta Gas Crown Royalties payable under the NewRoyalty Framework.

Interest and Other Income



Interest income . . . . . . . . . . . . . . . . . . . . . . — 9 12 50Processing and other . . . . . . . . . . . . . . . . . 51 62 159 222

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51 71 171 272

MDA-5

Interest and other income for the three and nine months ended September 30, 2009 were lower than the previousyear primarily due to lower processing fees as fewer third party volumes went through Exshaw’s operated facilities atSpirit River.

Operating Expenses and Transportation Costs



Operating expenses ($000) . . . . . . . . . . . . 2,270 2,166 6,748 5,818Operating expenses ($/Boe) . . . . . . . . . . . . 10.04 9.48 9.79 9.65

Transportation costs ($000) . . . . . . . . . . . . 514 456 1,550 1,309Transportation costs ($/Boe) . . . . . . . . . . . 2.27 2.00 2.25 2.17

Operating and transportation costs increased in the third quarter of 2009 primarily due to increased liquids volumecompared to 2008. Year-to-date costs for the first nine months of 2009 increased in comparison to the same period in2008 primarily due to higher production volumes. In addition, the per unit transportation costs were higher due toincreased oil production in 2009 relative to 2008.

General & Administrative (“G&A”) Expenses



G&A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 610 620 2,020 2,178Capitalized G&A . . . . . . . . . . . . . . . . . . . . (247) (309) (763) (1,132)

Net G&A . . . . . . . . . . . . . . . . . . . . . . . . . . 363 311 1,257 1,046

Net G&A ($/Boe) . . . . . . . . . . . . . . . . . . . . (1.61) (1.36) (1.82) (1.73)

Net G&A expenses for the three and nine months ended September 30, 2009 increased 17% and 20%,respectively, from the corresponding periods in 2008 despite lower gross G&A expenses as a result of lowercapitalized costs. Net G&A expenses averaged $1.61 and $1.82 per Boe for the three and nine months endedSeptember 30, 2009, compared to $1.36 and $1.73 per Boe for the corresponding periods in 2008.

Stock-Based Compensation Expense



Stock-based compensation expense(non-cash) . . . . . . . . . . . . . . . . . . . . . . 93 111 289 334

Exshaw used the fair value based method for the determination of all non-cash related stock-based compensationcosts. Stock-based compensation expense of $93,000 was recorded in the third quarter of 2009 relating to Exshaw’sstock option plan compared to $111,000 in the third quarter of 2008. Year-to-date stock-based compensation expensein 2009 was $289,000 compared to $334,000 for 2008. The decrease was due to a lower underlying share price whichhad a corresponding impact on Exshaw’s stock based compensation expense.

Interest Expense



Interest expense . . . . . . . . . . . . . . . . . . . . . 148 3 443 121

$/Boe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.66 0.02 0.64 0.20

MDA-6

Interest expense for the three and nine month periods ended September 30, 2009 consisted of costs associated withExshaw’s flow-through share obligation, standby fee on its credit facility and bank interest charges. Total expensesincreased over 2008 due to a higher flow-through share obligation, standby fees and interest costs.

Depletion, Depreciation and Accretion (“DD&A”) ExpenseThree Months Ended Nine Months Ended


DD&A ($000) . . . . . . . . . . . . . . . . . . . . . . 6,664 5,626 20,049 14,571DD&A ($/boe) . . . . . . . . . . . . . . . . . . . . . . 29.47 24.63 29.08 24.16

DD&A expense was $6,664,000 for the third quarter of 2009 compared to $5,626,000 for the same period in 2008due to a higher DD&A rate. Year-to-date, DD&A expense increased due to higher production volumes and a higherDD&A rate. The 2009 DD&A rate increased due to higher finding costs during the year.

Income Taxes



Future income taxes (reduction) . . . . . . . . (857) 519 (2,291) 2,188

A future income tax reduction of $857,000 was recorded for the quarter ended September 30, 2009 compared to afuture income tax expense of $519,000 in the third quarter of 2008. Year-to-date, an income tax reduction of$2,291,000 was recorded for the first nine months compared to income tax expense of $2,188,000 in 2008. The incometax reductions resulted from losses recorded by Exshaw during the three and nine months periods ended September 30,2009.

Net Income



Net income (loss) . . . . . . . . . . . . . . . . . . . . (2,724) 1,527 (7,642) 7,330

A net loss was recorded for the third quarter of 2009 of $2,724,000 compared to net income of $1,527,000 for thethird quarter of 2008. Year-to-date for the fist nine months of 2009, a net loss of $7,642,000 was recorded compared tonet income of $7,330,000 for 2008. The net losses in 2009 were primarily due to the reduced commodity pricesreceived by Exshaw.


Overall Exshaw invested $3.2 million in the third quarter of 2009 compared to $5.5 million in the third quarter of2008. On a year-to-date basis, Exshaw spent $13.6 million in the first nine months of 2009 compared to $24.6 millionin the same period in 2008. The 2009 capital expenditures were consistent with Exshaw’s lower 2009 capital programcompared to 2008.



Capital expenditures . . . . . . . . . . . . . . . . . 3,157 5,452 13,577 24,594

Exshaw drilled two wells (1.5 net), and recompleted one well (1.0 net) in the third quarter of 2009. Drilling andcompletion costs totaled $1.9 million, equipping and facilities were $0.7 million, and land costs were $0.3 million.Exshaw also capitalized $0.2 million of G&A costs and $0.1 million of stock compensation costs in the third quarter of2009.


As At

($000) September 30, 2009 December 31, 2008

Net working capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (671) 2,501

MDA-7

At September 30, 2009, Exshaw’s net working capital deficit was $0.7 million compared to a working capitalsurplus of $2.5 million at December 31, 2008. Exshaw endeavored to keep its expenditures within its cash flow tomaintain a strong balance sheet and financial flexibility.

As at December 8, 2009, Exshaw had no outstanding debt and expected to be able to fund its capital expenditureprogram for 2009 using a combination of cash flow from operations and the use of its credit facility. As of the date ofthe Exshaw Quarterly MD&A, Exshaw had a financing arrangement with a Canadian chartered bank for an extendiblerevolving term loan in the amount of $19 million in addition to a $5 million operating line. At September 30, 2009, thefacilities were not drawn (Nil at September 30, 2008). The interest rate charged varied based on the amountoutstanding. Security for the facility included a general security agreement and a demand loan debenture secured by afirst floating charge over all assets of Exshaw. The revolving term credit facility had a 364 day extendible period plus aone-year maturity.

Capitalization

As at September 30, 2009 Exhaw had a total of 53.34 million common shares outstanding, as follows:

Issued and outstanding common shares Number of shares Amount

($000)

Balance, December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53,340,001 152,563Tax effect of flow-through share renunciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — (3,251)

Balance, September 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53,340,001 149,312

There was no change to Exshaw’s share capital in the third quarter of 2009. However, during the first quarter,Exshaw renounced $13,002,000 of Canadian exploration expenses related to flow-through shares it issued in 2008. Asat September 30, 2009, Exshaw estimated that it had an obligation of $12.4 million remaining from the December 9,2008 offering which had to be spent on qualifying exploration expenses prior to December 31, 2009.

Commitments

Exshaw has entered into a lease arrangement for office space to April 28, 2010. As of the date of the ExshawQuarterly MD&A, the future obligation of this commitment was $199,000.

Subsequent Events:

On November 10, 2009, Tourmaline acquired 90.6 percent of Exshaw’s outstanding common shares by issuing10.875 million Common Shares.

Critical Accounting Estimates:

The financial statements have been prepared in accordance with GAAP. A summary of significant accountingpolicies is presented in Note 1 to Exshaw’s December 31, 2008 financial statements included in this prospectus.Certain accounting policies are critical to understanding the financial condition and results of operations of Exshaw.

Income Taxes:

The determination of Exshaw’s income and other tax liabilities requires interpretation of complex laws andregulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment afterthe lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimatedand recorded.

Commitments and Contractual Obligations:

Other than with respect to Exshaw’s flow-through share obligations (see “Capitalization” above) there were nosignificant changes in Exshaw’s commitments or contractual obligations from those disclosed in the Exshaw AnnualMD&A (as defined below) included in this prospectus.

MDA-8

Disclosure Controls and Procedures:

Disclosure controls and procedures had been designed to ensure that information required to be disclosed byExshaw was accumulated and communicated to Exshaw’s management as appropriate to allow timely decisionsregarding required disclosure.

Business Risks and Uncertainties:

Exshaw monitored and complied with government regulations that affected its activities, although operations maybe adversely affected by changes in government policy, regulations or taxation. In addition, Exshaw maintained a levelof liability, property and business interruption insurance which was believed to be adequate for Exshaw’s size andactivities, but was unable to obtain insurance to cover all risks within the business or in amounts to cover all possibleclaims.

Impact of New Environmental Regulations:

Environmental legislation, including the Kyoto Accord, the federal government’s “EcoACTION” plan andAlberta’s Bill 3 – Climate Change and Emissions Management Amendment Act, was evolving in a manner that wasexpected to result in stricter standards and enforcement, larger fines and liability and potentially increased capitalexpenditures and operating costs. Given the evolving nature of the debate related to climate change and the resultingrequirements, it was not possible to determine the operational or financial impact of those requirements on Exshaw.

Accounting Policy Updates

In May 2009, the Canadian Institute of Chartered Accountants (CICA) amended its Handbook Section 3862,“Financial Instruments – Disclosures,” to include additional disclosure requirements about fair value measurement forfinancial instruments and liquidity risk disclosures. These amendments required a three level hierarchy that reflectedthe significance of the inputs used in making the fair value measurements. Fair values of assets and liabilities includedin Level 1 are determined by reference to quoted prices in active markets for identical assets and liabilities. Fair valuesof assets and liabilities in Level 2 included valuations using inputs other than quoted prices for which all significantoutputs are observable, either directly or indirectly. Fair values in Level 3 were based on inputs that are unobservableand significant to the overall fair value measurement. These amendments would be effective for Exshaw’s interim andannual financial statements beginning December 31, 2009.


In February 2008, the CICA Accounting Standards Board (“AcSB”) confirmed the changeover to IFRS fromCanadian GAAP will be required for publicly accountable enterprises for interim and annual financial statementseffective for fiscal years beginning on or after January 1, 2011, including comparatives for 2010. In response, as atDecember 8, 2009, Exshaw was in the process of developing its IFRS changeover plan and establishing a preliminarytimeline for the execution and completion of the conversion project.

Selected Quarterly Information ($000s)

2009 2008 2007

Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4

Average daily production(Boe/d) . . . . . . . . . . . . . . . . 2,458 2,524 2,595 2,380 2,483 2,108 2,011 1,970

Oil & gas sales . . . . . . . . . . . . 7,536 7,697 8,792 10,186 14,613 15,337 11,794 10,139Net income (loss) . . . . . . . . . . (2,724) (2,420) (2,498) (1,029) 1,527 3,797 2,006 1,261Net earnings (loss) per share –

basic . . . . . . . . . . . . . . . . . . $ (0.05) $ (0.05) $ (0.05) $ (0.02) $ 0.03 $ 0.08 $ 0.04 $ 0.03Net earnings (loss) per share –

diluted . . . . . . . . . . . . . . . . . $ (0.05) $ (0.05) $ (0.05) $ (0.02) $ 0.03 $ 0.07 $ 0.04 $ 0.02Total assets . . . . . . . . . . . . . . . 166,379 169,392 175,402 183,267 165,674 164,928 162,335 161,883Long term liabilities . . . . . . . . — 168 — — — — — —

MDA-9

Exshaw Oil Corp.

MANAGEMENT’S DISCUSSION AND ANALYSISFor the year ended December 31, 2008

The following Management’s Discussion and Analysis (“Exshaw Annual MD&A”) of financial results asprovided by the management of Exshaw Oil Corp. (“Exshaw”) should be read in conjunction with the comparativeaudited financial statements of Exshaw for the year ended December 31, 2008 and comparative information thereinincluded in this prospectus. This commentary is based on information available as at April 23, 2009.

The information contained herein contains forward-looking statements and assumptions, such as those relating toresults of operations and financial condition, capital spending, financing sources, commodity prices and costs ofproduction. By their nature, forward-looking statements are subject to numerous risks and uncertainties that couldsignificantly affect anticipated results in the future and, accordingly, actual results may differ materially from thosepredicted. Readers are cautioned that the assumptions used in the preparation of such information, although consideredreasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed onforward-looking statements.

All financial results are reported in Canadian dollars and production numbers are stated before Crown or lessorroyalties. Natural gas volumes are converted to barrels of oil equivalent (Boe) on the basis of six thousand cubic feet(Mcf) of gas to one barrel (Bbl) of oil.

Business

Exshaw is an oil and gas company engaged in the exploration, development and production of oil and natural gasin Western Canada.

Production

Three Months Ended Year Ended

December 31, 2008 December 31, 2007 December 31, 2008 December 31, 2007

Crude Oil (Bbls/d) . . . . . . . . . . . . . . . . . . . . . 419 625 450 250NGL (Bbls/d) . . . . . . . . . . . . . . . . . . . . . . . . . 88 75 83 42Natural Gas (Mcf/d) . . . . . . . . . . . . . . . . . . . 11,236 7,627 10,281 5,575

boe/d (6:1) . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,380 1,970 2,246 1,221

% natural gas production . . . . . . . . . . . . . . . . 79 65 76 76

For the year ended December 31, 2008, production averaged 2,246 Boe/d compared to 1,221 Boe/d for 2007. The84% increase in volumes was primarily accomplished through drilling resulting in increased production in all ofExshaw’s main areas of operations. Exshaw brought on 19 new wells during the year.

For the three month period ended December 31, 2008, Exshaw’s average production increased by 21% to2,380 Boe/d compared to the fourth quarter of 2007. The average production increased despite maximum ratelimitations (“MRLs”) in Spirit River which resulted in a number of wells being shut-in during the quarter. These wellswere brought on production in 2009 as Exshaw received Good Production Practice (“GPP”) on the wells from theERCB in March, 2009. Exshaw’s average production for the last week of March 2009 was 3,280 boe/d.

Natural gas sales volumes increased 47% to 11,236 Mcf/d during the three months ended December 31, 2008compared to 7,627 Mcf/d for the same period of 2007 due to increased production in Elmworth and Pouce Coupe.

Crude oil and natural gas liquids sales volumes decreased 28% to 507 Boe/d for the three months endedDecember 31, 2008 compared to 2007. The decrease was due to lower liquids production in Spirit River due to naturaldeclines and the aforementioned MRL issues.

MDA-10

Commodity Pricing



Natural Gas ($/Mcf) . . . . . . . . . . . . . . . . . . . 7.17 6.83 8.69 6.80Crude Oil ($/Bbl) . . . . . . . . . . . . . . . . . . . . . . 57.64 83.26 98.11 79.43NGL ($/Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . 67.97 81.52 101.85 74.93

Average price ($/Boe) . . . . . . . . . . . . . . . . . . 46.52 55.94 63.17 49.87

Overall prices received by Exshaw for the three month period ended December 31, 2008, decreased by 17%compared to the fourth quarter of 2007. Natural gas was 5% higher, crude oil was 31% lower and NGL were 17%lower.

Exshaw’s realized average yearly price increased from 2007 due to higher commodity prices for all of itsproducts. The change in Exshaw’s realized prices are consistent with the overall market changes as Exshaw did notenter into any hedges or fixed price contracts in 2008.

Crude Oil and Gas Sales



$000 % $000 % $000 % $000 %

Natural Gas . . . . . . . . . . . . . . . . . . . . . . 7,413 73 4,795 47 32,686 63 13,829 62Crude Oil . . . . . . . . . . . . . . . . . . . . . . . . 2,221 22 4,785 47 16,157 31 7,261 33NGL . . . . . . . . . . . . . . . . . . . . . . . . . . . 552 5 559 6 3,088 6 1,140 5

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,186 100 10,139 100 51,931 100 22,230 100

Oil and gas revenues totaled $10.2 million in the fourth quarter of 2008 compared to $10.1 million for the samequarter of 2007. The increase was due to higher natural gas production volumes and prices which more than offset thelower liquids production volumes and prices in the fourth quarter of 2008.

Total oil and gas sales for the year ended December 31, 2008 was up 133% due to higher prices on all productsand higher volumes in all areas compared to 2007.

Royalties


($000) December 31, 2008 December 31, 2007 December 31, 2008 December 31, 2007

Crown royalties . . . . . . . . . . . . . . . . . . . . . . . 1,721 1,851 9,126 4,313Other royalties . . . . . . . . . . . . . . . . . . . . . . . . 504 425 2,399 1,131

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,225 2,276 11,525 5,444

Royalty expense in the fourth quarter of 2008 decreased 2% compared to the same period in 2007 due to a minorreduction in Exshaw’s overall royalty rate primarily due to lower commodity prices.

Royalty expense for 2008 increased 112% compared to 2007 due to higher production volumes and highercommodity prices. The overall effective royalty rate in 2008 was 22% compared to 24% in 2007. The decreased ratewas due to deep gas royalty incentives received by Exshaw on its Elmworth production and a higher gas cost allowancereceived in the current year.

On October 25, 2007, the Province of Alberta announced a framework to increase royalty rates entitled the NewRoyalty Framework (“NRF”). The NRF was effective on January 1, 2009 subject to transitional provisions announcedin November, 2008. Under the NRF, Crown royalties payable for crude oil and natural gas are set by sliding rate

MDA-11

formulas containing separate components that account for price and well production. Maximum royalty rates were setto increase from 35 percent to 50 percent of a reference price. Under the transitional provisions Exshaw could opt for arevised royalty rate formula on new wells drilled after November 18, 2008 which are between 1,000 and 3,500 metresin depth. This would reduce the maximum royalty rate on these wells. Furthermore in March, 2009, the Province ofAlberta announced additional incentive programs intended to provide a temporary relief for new wells. These programsinclude drilling credits and maximum royalty rates fixed at 5% for one year on the first 50,000 barrels or 0.5 bcfproduced. These incentives would improve the economics on any new qualifying wells drilled after April 1, 2009.

Interest and Other Income



Interest income . . . . . . . . . . . . . . . . . . . . . . . 21 109 71 1,167Processing and other . . . . . . . . . . . . . . . . . . . 39 26 261 113

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60 135 332 1,280

Total interest and other income was lower in 2008 compared to 2007 for both the full year and the fourth quarter,respectively, due to Exshaw’s lower average cash balance over the same periods in 2007. This decrease was partiallyoffset by processing fees as more third party volumes went through Exshaw’s operated facilities at Spirit River.

Operating Expenses and Transportation Costs



Operating expenses ($000) . . . . . . . . . . . . . . 2,190 1,407 8,008 4,291

Operating expenses ($/Boe) . . . . . . . . . . . . . 10.00 7.76 9.74 9.62

Transportation costs ($000) . . . . . . . . . . . . . . 441 413 1,751 831

Transportation costs ($/Boe) . . . . . . . . . . . . . 2.01 2.28 2.13 1.86

Operating costs increased in the fourth quarter of 2008 compared to 2007 primarily due to increased productionvolumes. Operating costs per Boe also increased during this period due to higher fixed costs at Spirit River and highergathering and processing costs at Elmworth.

Operating expenses for the year ended December 31, 2008 were $8.0 million compared to $4.3 million for thecorresponding period in 2007. The 87% increase in total costs was consistent with the 84% increase in productionvolumes over the same period.

Transportation costs for the three months ended December 31, 2008 increased over the corresponding period in2007 due to higher production volumes. However, the per Boe transportation costs decreased due to lower oilproduction which generally has a higher transportation cost than natural gas.

The transportation costs for the year ended December 31, 2008 were also higher due to higher productionvolumes. In addition, the per unit transportation costs were higher due to higher oil production in 2008 relative to 2007.

General & Administrative (“G&A”) Expenses



G&A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 854 587 3,032 1,988Capitalized G&A . . . . . . . . . . . . . . . . . . . . . . (426) (309) (1,558) (933)

Net G&A . . . . . . . . . . . . . . . . . . . . . . . . . . . . 428 278 1,474 1,055

Net G&A ($/Boe) . . . . . . . . . . . . . . . . . . . . . 1.95 1.54 1.79 2.37

MDA-12

Net G&A costs for the three months ended December 31, 2008 increased 54% compared to the same period in2007 primarily due to higher consulting, professional and lease office costs. The higher costs resulted in increased perunit costs over the same period.

For the year ended December 31, 2008, the net G&A increased 40% due to higher staff costs, increased consultingand professional fees and higher lease office costs. Notwithstanding, Net G&A per Boe decreased 24% primarily dueto higher production volumes. The annual G&A per Boe should continue to decrease as Exshaw’s production volumesincrease.

Stock-based Compensation Expense



Stock-based compensation expense(non-cash) . . . . . . . . . . . . . . . . . . . . . . . . . (27) 108 308 321

Exshaw used the fair value method for the determination of all non-cash related stock-based compensation costs.A stock-based compensation recovery of $26,741 was recorded in the fourth quarter relating to Exshaw’s stock optionplan compared to an expense of $107,520 in the fourth quarter of 2007. The recovery was due to the reduced value ofthe stock options issued to consultants which must be fair valued each quarter. This also contributed to the decrease inthe stock-based compensation expense for the full year 2008 compared to 2007.

Interest Expense



Interest expense . . . . . . . . . . . . . . . . . . . . . . . 2 122 —$/Boe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.01 — 0.15 —

Interest expense related primarily to Exshaw’s flow-through share obligation outstanding in the year.

Depletion, Depreciation and Accretion (“DD&A”)



DD&A ($000) . . . . . . . . . . . . . . . . . . . . . . . . 6,138 4,060 20,709 10,339DD&A ($/boe) . . . . . . . . . . . . . . . . . . . . . . . . 28.04 22.40 25.19 23.19

DD&A expense was $6,138,425 for the quarter compared to $4,059,692 for the same period in 2007 due to higherproduction volumes and a higher DD&A rate. The DD&A rate increased due to higher finding and developments costsin 2008 primarily resulting from Exshaw focusing on drilling previously booked proved undeveloped reserves andincreased facility costs.

Income Taxes



Future income taxes . . . . . . . . . . . . . . . . . . . . (122) 470 2,065 424

In the fourth quarter of 2008 a future income tax recovery of $122,234 was recorded compared to an expense of$424,126 for the fourth quarter of 2007. This future income tax recovery resulted from the loss recorded in the fourthquarter of 2008.

Exshaw did not pay any cash income taxes in 2008 nor did it expect to pay any in 2009 based on its existing taxpools, planned capital expenditures and the most recent forecast of its taxable income.

MDA-13

At December 31, 2008, Exshaw had tax pools of approximately $136.4 million. In addition, Exshaw was torenounce $13 million of its Canadian Exploration Expenses in the first quarter of 2009 related to flow-through sharesissued on December 9, 2008 which was expected to reduce Exshaw’s tax pools in 2009.

Net Income



Net income (loss) . . . . . . . . . . . . . . . . . . . . . . (1,029) 1,261 6,301 805

Exshaw incurred a net loss for the fourth quarter of 2008 of $1,029,000 compared to net income of $1,261,000 forthe fourth quarter of 2007. The loss was primarily attributable to lower overall commodity prices, higher operatingcosts and higher depletion expense.

For the year ended December 31, 2008, Exshaw recorded net income of $6.3 million compared to $805 thousandin 2007. The increased net income was primarily driven by higher volumes and commodity prices compared to 2007.


For the year ended December 31, 2008, Exshaw invested $41.5 million compared to $67.9 million in the prioryear. The decrease was consistent with Exshaw’s plan to spend significantly less dollars in 2008 compared to 2007. Forthe current quarter, Exshaw spent $16.9 million compared to $21.9 million in the fourth quarter of 2007. The decreasewas consistent with Exshaw’s reduced capital program for the year.



Capital expenditures . . . . . . . . . . . . . . . . . . . 16,946 21,925 41,539 67,862

Exshaw drilled eight wells (7.6 net), completed eight wells (7.6 net) and recompleted two wells (2.0 net) in thequarter. Drilling and completion costs totaled $11.6 million, equipping and facilities were $4.6 million, land andseismic costs were $0.4 million, respectively. Exshaw also capitalized $0.3 million of G&A costs and $0.1 million ofstock compensation costs in the current quarter.

For the year, Exshaw drilled 18 wells (15.5 net), completed 19 wells (16.3 net) and recompleted 5 wells (5 net).Drilling and completion costs totaled $24.2 million, equipping and facilities were $13.3 million, land and seismic costswere $3.5 million, property acquisitions were $0.2 million and dispositions of $0.8 million, respectively. Exshaw alsocapitalized $1.1 million of G&A costs and $0.4 million of stock compensation costs in the current year.

Exshaw’s total acreage at December 31, 2008 was 20,802 hectares.


As At

($000) December 31, 2008 December 31, 2007

Net working capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,501 2,456

At December 31, 2008, Exshaw’s net working capital was $2.5 million. Exshaw had endeavored to maintain astrong balance sheet to provide it with as much financial flexibility as possible for the future. As at April 23, 2009,Exshaw had no outstanding debt and expected to be able to fund its capital expenditure program for 2009 using acombination of cash flow from operations and the use of its credit facility. As at the date of the Exshaw AnnualMD&A, Exshaw had a credit facility with a chartered bank with a borrowing capacity of $15 million and a $5 millionoperating line, both of which were up for renewal at the end of May 2009.

MDA-14

Capitalization

As at December 31, 2008, Exshaw had a total of 53.3 million common shares outstanding, as follows:

Issued and outstanding common shares Number of shares Amount

($000)

Balance, December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49,400 146,444Flow-through shares issued . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,940 13,002Share issue costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — (801)Tax effect on share issue costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 221Tax effect of flow-through share renunciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — (6,303)

Balance, December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53,340 152,563

On December 9, 2008, Exshaw issued 3,940,000 common shares for $3.30 per share on a flow-through basis fortotal proceeds of $13,002,000. Exshaw had planned exploration expenditures sufficient to ensure fulfillment of itsobligations in 2009.

Commitments

In the normal course of business, Exshaw was obligated to make future payments. The following obligationsrepresent commitments that were known and non-cancelable.

Payment due by period Total 2009 2010

Operating lease . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $454 $341 $113

As at December 31, 2008, Exshaw estimated that it had an obligation remaining in the amount of $13.0 millionfrom the December 9, 2008 flow-through share offering which had to be spent on qualifying exploration expendituresprior to December 31, 2009.

Critical Accounting Estimates

The financial statements have been prepared in accordance with GAAP. A summary of significant accountingpolicies is presented in Note 1 to Exshaw’s December 31, 2008 financial statements included in this prospectus.Certain accounting policies are critical to understanding the financial condition and results of operations of Exshaw.

Income Taxes

The determination of Exshaw’s income and other tax liabilities requires interpretation of complex laws andregulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment afterthe lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimatedand recorded.

Disclosure Controls and Procedures

Disclosure controls and procedures were designed to ensure that information required to be disclosed by Exshawwas accumulated and communicated to Exshaw’s management as appropriate to allow timely decisions regardingrequired disclosure.

Business Risks and Uncertainties

Exshaw monitors and complies with current government regulations that affect its activities, although operationsmay be adversely affected by changes in government policy, regulations or taxation. In addition, Exshaw maintains alevel of liability, property and business interruption insurance which is believed to be adequate for Exshaw’s size andactivities, but is unable to obtain insurance to cover all risks within the business or in amounts to cover all possibleclaims.

MDA-15

Impact of New Environmental Regulations

Environmental legislation, including the Kyoto Accord, the federal government’s “EcoACTION” plan andAlberta’s Bill 3 – Climate Change and Emissions Management Amendment Act, is evolving in a manner expected toresult in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures andoperating costs. Given the evolving nature of the debate related to climate change and the resulting requirements, it wasnot possible to determine the operational or financial impact of those requirements on Exshaw.

Accounting Changes

On January 1, 2008, Exshaw adopted the following new accounting standards issued by the Canadian Institute ofChartered Accountants (the “CICA”). These standards had no impact on previously reported amounts for prior periods.

(i) Financial Instruments – Recognition and Measurement

Financial instruments are required to be measured at fair value on the balance sheet upon initial recognitionof the instrument. Measurement in subsequent periods depends on whether the financial instrument has beenclassified in one of the following categories: held-for-trading; available-for-sale; held-to-maturity; loans andreceivables, or other financial liabilities as defined under the new standard.

Under adoption of these standards, cash and cash equivalents are designated as held-for-trading and aremeasured at carrying value, which approximates fair value due to the short-term nature of these instruments.Accounts receivable and accrued revenues are designated as loans and receivables. Accounts payable andaccrued liabilities and long-term debt are designated as other liabilities. Risk management assets andliabilities being derivative financial instruments are classified as held-for-trading.

Derivatives

At the date of the Exshaw Annual MD&A, Exshaw had not entered into any derivatives to manage the pricerisk attributable to the sale of petroleum and natural gas production. Refer to Note 8 of Exshaw’s annualfinancial statements for the year ended December 31, 2008 included in this prospectus for additionaldisclosure on Exshaw’s risk management objectives.

Embedded Derivatives

Exshaw had elected to recognize, as separate assets and liabilities, only those embedded derivatives in hybridinstruments issued, acquired or substantively modified after January 1, 2003. Exshaw had not identified anysignificant embedded derivatives which require separate recognition and measurement.

Effective Interest Method

Transaction costs attributable to the financial instruments classified as other than held-for-trading areincluded in the recognized amount of the related financial instrument and expensed over the life of theresulting financial instrument using the effective interest rate method. Prior to January 1, 2008, transactioncosts were recorded as deferred charges and recognized in net earnings on a straight-line basis over the life ofthe financial instrument. On adoption, transaction costs are amortized using the effective interest ratemethod. Exshaw determined that it had no such items that would impact the financial statements for the yearended December 31, 2008.

(ii) Hedging

The new standard specifies the circumstances under which hedge accounting is permissible and how hedgeaccounting may be performed. On adoption of these standards, Exshaw did not have any agreements orcontracts to which hedge accounting would apply.

(iii) Comprehensive Income

Comprehensive income is the change in shareholders’ equity during a period from transactions and otherevents from non-owner sources. This standard requires certain gains and losses that would otherwise berecorded as part of net earnings to be presented in “other comprehensive income or loss” until it is consideredappropriate to recognize into net earnings. The standard requires the presentation of comprehensive income,and its components in a separate financial statement. Exshaw determined that it had no items that wouldaffect comprehensive income, nor accumulated other comprehensive income as at and for the year endedDecember 31, 2008 and therefore comprehensive income equals net income.

MDA-16

(vi) Equity

Exshaw adopted Section 3251, Equity, which establishes standards for the presentation of equity and changesin equity during the reporting period. At the date of this Exshaw Annual MD&A, the adoption of thisstandard had not had a material impact upon Exshaw’s financial statements.

(vii) Financial Instruments – Disclosures and Presentation

On January 1, 2008, Exshaw also adopted CICA Handbook Section 3862, Financial Instruments –Disclosures, and Section 3863, Financial Instruments – Presentation. Section 3862 and 3863 establishstandards for the presentation and disclosure of information that enable users to evaluate the significance offinancial instruments to the entity’s financial position, and the nature and extent of risks arising fromfinancial instruments and how the entity manages these risks. The implementation of these standards did notimpact Exshaw’s financial results; however, it did result in additional note disclosure.

(viii) Capital Disclosures

On January 1, 2008, Exshaw adopted CICA Handbook Section 1535, Capital Disclosures. This sectionestablishes standards for disclosing information about an entity’s capital and how it is managed. This sectionspecifies disclosure about objectives, policies and processes for managing capital, quantitative data aboutwhat an entity regards as capital, whether an entity has complied with all capital requirements, and if it hasnot complied, the consequences of such non-compliance. The implementation of this standard did not impactExshaw’s financial results; however, it did result in additional note disclosure.



Canadian public entities will need to begin reporting under the IFRS by the first quarter of 2011 withappropriate comparative data from the prior year. Under IFRS, there is significantly more disclosurerequired, specifically for quarterly reporting. Further, while IFRS uses a conceptual framework similar toCanadian GAAP, there are significant differences in accounting policy which must be addressed.

Selected Quarterly Information ($000s)

2008 2007

Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1

Average daily production(Boe/d) . . . . . . . . . . . . . . . . . . 2,380 2,483 2,108 2,011 1,970 1,286 898 716

Oil & gas sales . . . . . . . . . . . . . . 10,186 14,613 15,337 11,794 10,139 4,793 4,058 3,239Net income (loss) . . . . . . . . . . . . (1,029) 1,527 3,797 2,006 1,261 (494) 17 20Net earnings (loss) per share –

basic . . . . . . . . . . . . . . . . . . . . $ (0.02) $ 0.03 $ 0.08 $ 0.04 $ 0.03 $ (0.01) $ 0.00 $ 0.00Net earnings (loss) per share –

diluted . . . . . . . . . . . . . . . . . . $ (0.02) $ 0.03 $ 0.07 $ 0.04 $ 0.02 $ (0.01) $ 0.00 $ 0.00Total assets . . . . . . . . . . . . . . . . 183,267 165,674 164,928 162,335 161,883 152,806 149,692 147,061Long term liabilities . . . . . . . . . . — — — — — — — —

Selected Annual Information ($000s)

2008 2007 2006

Average daily production (boe/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,246 1,221 581Oil & gas sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51,931 22,230 476Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,301 805 (1,178)Net earnings (loss) per share – basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.13 $ 0.02 $ (0.03)Net earnings (loss) per share – diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.13 $ 0.02 $ (0.03)Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 183,267 161,883 124,169Long term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — —

MDA-17

Altia Energy Ltd.

MANAGEMENT’S DISCUSSION & ANALYSIS

for the Three and Nine Months ended December 31, 2009

This management’s discussion and analysis (the “Altia Quarterly MD&A”) report is intended to provideadditional information on Altia for the period ended December 31, 2009 and should be read in conjunction with thefinancial statements of Altia for the three and nine months ended December 31, 2009 and for the year ended March 31,2009 (the “Altia Annual Financial Statements”) included in this prospectus. The financial statements were preparedin accordance with Canadian Generally Accepted Accounting Principles and are presented in Canadian dollars. Perbarrel of oil equivalent amounts (Boe or Boe/d) have been calculated using a conversion rate of six thousand cubic feetof natural gas to one barrel of oil (6:1). This Altia Quarterly MD&A is dated January 15, 2010.

PRODUCTION

Natural gas is the principal component of production for Altia. Average year to date production of natural gas was7,339 Mcf/d compared to the prior year average of 7,594 Mcf/d. NGL production averaged 6 Bbls/d, and compares tothe prior year rate of 8 Bbls/d, oil production averaged 9 Bbls/d and compares to 11 Bbls/d for the prior year. Totalproduction for the period using the 6:1 equivalence was 1,238 Boe/d compared to the prior year rate of 1,285 Boe/d.The decrease in production is due to natural declines, as Altia did not bring any new wells on to production during thenine months ending December 31, 2009. For the same reason, Altia had similar production declines for the threemonths ending December 31, 2009 (1,109 Boe/d) over the same period in 2008 (1,580 Boe/d).

Three MonthsEnded

December 312009

Three MonthsEnded

December 312008

Nine MonthsEnded

December 312009

Nine MonthsEnded

December 312008

Natural Gas (Mcf/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,576 9,368 7,339 7,594NGL (Bbls/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 8 6 8Crude Oil (Bbls/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 11 9 11

Total (Boe/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,109 1,580 1,238 1,285

COMMODITY PRICING & MARKETING

All natural gas, natural gas liquids (“NGL”) and oil production was sold on the spot market to major purchasers.At the date of the Altia Quarterly MD&A, Altia did not have any long term contracts or hedges. Natural gas pricesvaried during the period from a high of $4.62/Mcf in the third quarter of 2009 to a low of $2.90/Mcf in the secondquarter of 2009. Natural gas and NGL prices fell year-over-year as well as for the three month periods endingDecember 31, 2009 and 2008, respectively, while oil prices improved.

Three MonthsEnded

December 312009

Three MonthsEnded

December 312008

Nine MonthsEnded

December 312009

Nine MonthsEnded

December 312008

Natural Gas ($/Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.62 6.67 3.55 7.93NGL ($/Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74.90 73.63 68.66 100.89Crude Oil ($/Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67.57 57.43 61.96 93.77

Boe ($/Boe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28.24 40.34 21.86 48.32

REVENUE ($000)

Altia’s principal source of revenue was from sales of natural gas, NGL and oil production. Other income wasderived principally from interest on shareholder loans. Total revenue for the nine months ended December 31, 2009 of$7,445 (three months – $2,882) decreased compared to the same period in the prior year of $17,072 (three months –$5,857) due to lower annual natural gas sales volumes and a decrease in the annual price received for natural gas.

MDA-18

Three MonthsEnded

December 312009

Three MonthsEnded

December 312008

Nine MonthsEnded

December 312009

Nine MonthsEnded

December 312008

Natural Gas Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,792 5,747 7,171 16,568NGL Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 42 94 199Crude Oil Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71 78 178 297Other Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — (10) 2 8

Total Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,882 5,857 7,445 17,072

ROYALTY EXPENSE ($000)

Altia royalties were paid principally to the provincial governments of British Columbia and Alberta. Royaltyexpenses for the three and nine month periods ended December 31, 2009 decreased from the same periods in the prioryear due to decreases in production revenues and the benefit of the royalty drilling incentives in British Columbia.

Three MonthsEnded

December 312009

Three MonthsEnded

December 312008

Nine MonthsEnded

December 312009

Nine MonthsEnded

December 312008

Royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 493 1,250 1,118 3,631

OPERATING COST & TRANSPORTATION EXPENSE ($000)

The major portion of Altia’s production was processed in company owned and operated facilities located in theDawson area of British Columbia. Altia used third party facilities and incurred fees for processing its remaining minorproduction volumes. Altia did not receive any significant fees from other sources for processing/transportation ofproduction volumes through its owned facilities. Operating and transportation/marketing costs decreased compared to2008. On a unit of production basis, operating costs for the nine month period ending December 31, 2009 decreased to$2.87/Boe (three months – $1.55) compared to 2008 costs of $4.49/Boe (three months – $2.73), as production volumesin a high operating and transportation cost area decreased significantly.

Three MonthsEnded

December 312009

Three MonthsEnded

December 312008

Nine MonthsEnded

December 312009

Nine MonthsEnded

December 312008

Operating Expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 158 398 571 1,193Transportation & Sales Expense . . . . . . . . . . . . . . . . . . . . . . . . 113 136 406 393

Total Expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 271 534 977 1,586

GENERAL & ADMINISTRATIVE COSTS ($000)

A portion of the general and administrative costs were capitalized and recorded as capital expense required todevelop and explore for future production properties. The total amount capitalized is noted in the table below.

Three MonthsEnded

December 312009

Three MonthsEnded

December 312008

Nine MonthsEnded

December 312009

Nine MonthsEnded

December 312008

G & A Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 432 389 1,282 1,204Capitalized G & A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (143) (183) (418) (560)

G & A Expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 289 206 864 644

MDA-19

STOCK BASED COMPENSATION ($000)

Stock based (non-cash) compensation was calculated using the Black Scholes model as described within the notesto the Altia Annual Financial Statements.

Three MonthsEnded

December 312009

Three MonthsEnded

December 312008

Nine MonthsEnded

December 312009

Nine MonthsEnded

December 312008

Stock Based Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . 199 8 228 49

DEPLETION, DEPRECIATION & ACCRETION ($000)

Altia followed the full cost method of accounting as described in the CICA’s accounting guideline AcG-16. Thedepletion expense was prepared utilizing the independent reserve report prepared by Sproule Associates Limited for theyear ended March 31, 2009 adjusted for production and revisions due to drilling success. An amount of $9,535 forundeveloped land value was excluded from the depletion calculation. The decrease in depletion expense over the prioryear was principally due to a decrease in production, combined with a decrease in the depletion rate per Boe. On thebasis of barrels of equivalent (Boe) the average rate of depletion for the nine months ended December 31, 2009 was$18.21/Boe (three months – $17.21/Boe) decreasing from a rate of $22.42/Boe (three months – $21.02/Boe) for thesame period in 2008.

Three MonthsEnded

December 312009

Three MonthsEnded

December 312008

Nine MonthsEnded

December 312009

Nine MonthsEnded

December 312008

Depletion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,756 3,056 6,200 7,919Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 4 8 10Accretion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 12 25 33

Total DD & A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,768 3,072 6,233 7,962

NET INCOME ($000)

Net income decreased for the three and nine months ended December 31, 2009 over the same periods in 2008 dueto mainly decreases in production revenues.

Three MonthsEnded

December 312009

Three MonthsEnded

December 312008

Nine MonthsEnded

December 312009

Nine MonthsEnded

December 312008

Net Income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (172) 787 (2,060) 3,200

TAX POOLS ($000)

The tax pool balances as at December 31, 2009 were as follows and are noted in further detail in the notes to theAltia Annual Financial Statements.

As at December 31 2009

Undepreciated Capital Cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,901Canadian Exploration Expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26,350Canadian Development Expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,782Canadian Oil & Gas Property Expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,976ACRI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 781Non Capital Loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,750

Total Pools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50,540

MDA-20

CAPITAL EXPENDITURES ($000)

Capital expenditures are noted for the various categories of investment. Altia drilled three gross wells andcompleted one gross well during the nine month period ending December 31, 2009.

Three MonthsEnded

December 312009$M

Three MonthsEnded

December 312008$M

Nine MonthsEnded

December 312009$M

Nine MonthsEnded

December 312008$M

Land Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 1,067 168 2,557Geological & Geophysical . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 80 30 953Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,516 3,083 3,793 5,464Completion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 482 1,295 474 1,694Equipping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 404 1,909 252 3,622Capitalized G & A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 143 183 418 560Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — (41) —Sub-Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,591 7,617 5,094 14,850Disposition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — —

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,591 7,617 5,094 14,850

CAPITAL RESOURCES AND SHARE CAPITAL

On July 22, 2009, Altia renewed a business corporation agreement with the Alberta Treasury Branch to have arevolving credit facility of $9,000,000. Interest on the Revolving Operating Demand Loan was at the Alberta TreasuryBranch Prime Rate plus an interest rate ranging from 1.25 percent to 2.50 percent. At December 31, 2009 theRevolving Operating Demand Loan interest was calculated at the Alberta Treasury Branch Prime Rate plus 1.25percent. This facility was allowed to revolve and fluctuate at Altia’s discretion without fixed repayment terms and wassubject to an annual review. As a result of the acquisition of Altia by Tourmaline the bank debt was repaid in January2010 and the facility loan was cancelled.

The credit facility drawn at the Alberta Treasury Branch at December 31, 2009 was $4.9 million.

As of December 31, 2009 a total of 41,901,293 common shares had been issued for net proceeds of $41,309,811.On January 15, 2010 all of the outstanding shares of Altia were purchased by Tourmaline, Refer to the “SubsequentEvent” discussion below for further information.

COMMITMENTS

As at December 31, 2009, Altia was committed to a long-term lease for office space of:

YearYear-to-date

($000s)

2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3322011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3322012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83

747

On November 18, 2008, Altia signed a five year contract with Westcoast Energy Inc. for 5 Mmcf a day of firmeastbound transmission service commencing approximately November 1, 2009. Altia estimated the undiscounted costover the five year contract at $1.2 million at the time of the Altia Quarterly MD&A.

RELATED PARTY TRANSACTION

As of December 31, 2009, Altia had incurred drilling costs of $0.33 million (2008 – $1.0 million) to a companythat was partially owned by a director of Altia. Altia had a shareholder loan receivable in the amount of $0.29 million(2008 – $0.28) as described in Note 6 to the Altia Annual Financial Statements. These transactions were recorded at theexchange amount.

MDA-21

SUBSEQUENT EVENT

On January 15, 2010, Tourmaline purchased 100% of the outstanding shares of Altia for a total consideration of$105 million comprised of $3 million in cash plus 6.8 million Common Shares valued at $15 per share. The bank debtwas repaid in full and the Alberta Treasury Bank facility loan was cancelled.

FINANCIAL RISK MANAGEMENT

a) Fair values of financial assets and liabilities

Financial instruments of Altia consisted mainly of cash and short-term investments, deposits, receivables andpayables debt and due to the short term nature of each, the fair values approximated their carrying value.

Band debt bears interest at a floating market rate and accordingly the fair value approximates its carryingvalue.

b) Credit risk

Substantially all of the accounts receivable were with joint venture partners, and oil and gas marketers andwere subject to normal industry credit risks. Receivables from joint venture partners were generally collectedwithin one to three months. Altia attempted to mitigate this risk by entering into transactions with long-standing and reputable organizations and by obtaining partner approval of significant capital expendituresand payment of cash advances wherever possible. Further risk existed with joint venture partners asdisagreements occasionally arose and may increase the potential for non-collection. At the date of the AltiaQuarterly MD&A, there was no indication that amounts were non-collectible and as such, an allowance wasnot set-up. Receivables related to oil and gas marketers were normally collected on the 25th day of the monthfollowing production. To mitigate the risk of these receivables, Altia predominately established relationshipswith marketers who had strong credit ratings and solid reputations. At the date of the Altia Quarterly MD&A,Altia had not experienced any issues in collecting from its oil and gas marketers. The accounts receivablebalance at the end of the period represents the Company’s maximum exposure to credit risk.


Altia was exposed to fluctuations in interest rates on its bank debt in response to changes in market interestrates. At December 31, 2009, the increase or decrease for each one percent change in interest rates amountedto approximately $34 thousand in interest rate expense for the nine months ended December 31, 2009(December 31, 2008 – nil).


Altia’s objectives when managing capital were to (i) deploy capital to provide an appropriate return oninvestment to its shareholders; (ii) maintain financial flexibility in order to preserve its ability to meetfinancial obligations; and (iii) maintain a capital structure that provides financial flexibility to execute onstrategic acquisitions.

Altia’s strategy was designed to maintain a flexible capital structure consistent with the objectives as statedabove and to respond to changes in economic conditions and the risk characteristics of the underlyingpetroleum and natural gas assets.

Altia considered its capital structure to include share capital, bank debt and working capital. In order tomaintain or adjust its capital structure, Altia could from time to time issue new shares, seek debt financingand adjust its capital spending to manage projected debt levels.

In order to facilitate the management of capital expenditures and projected net debt, Altia prepared annualbudgets which were updated as necessary depending upon varying factors including current and forecastnatural gas and crude oil prices, capital expenditures and general industry conditions. The annual budgetswere approved by Altia’s Board of Directors.

At December 31, 2009, Altia had a negative working capital of $5.1 million which included the bank debt of$4.9 million.

Altia’s share capital was not subject to external restrictions. At the date of the Altia Quarterly MD&A, Altiahad not declared or paid any dividends since the incorporation date of June 12, 2003 and did not contemplatedoing so in the foreseeable future.

MDA-22

APPLICATION OF CRITICAL ACCOUNTING ESTIMATES

The financial statements were prepared in accordance with Canadian Generally Accepted Accounting Principles(“GAAP”). A summary of significant accounting policies is presented in Note 1 to the Altia Annual FinancialStatements. Certain accounting policies require that management make appropriate decisions with respect to theformulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses.Management of Altia reviewed its estimates on a regular basis. The emergence of new information and changedcircumstance may have resulted in actual results or changes to estimated amounts that differ materially from currentestimates. The following discussion identifies the critical accounting policies and practices of Altia and helps assess thelikelihood of materially different results being reported.

RESERVES

Under the National Instrument 51-101 (“NI 51-101”), “Proved” reserves are defined as those reserves that can beestimated with a high degree of certainty to be recoverable. The level of certainty should result in at least 90%probability that the quantities actually recovered will equal or exceed the estimated Proved reserves. It does not meanthat there is a 90% probability that the Proved reserves will be recovered; it means there must be at least 90%probability that the given amount or more will be recovered.


These oil and gas reserve estimates are made using all available geological and reservoir data, as well as historicalproduction data. All of Altia’s reserves were evaluated and reported on by independent qualified reserves evaluators.However, revisions could occur as a result of various factors including: actual reservoir performance, changes in priceand cost forecasts or, a change in Altia’s plans. Reserve changes would impact the financial results as reserves are usedin the calculation of depletion and are used to assess whether asset impairment occurs.

DEPLETION AND DEPRECIATION

Altia followed the full cost method of accounting for oil and natural gas properties. Under this method, all costsrelated to the acquisition of, exploration for and development of oil and natural gas reserves are capitalized whethersuccessful or not. Depletion of the capitalized oil and natural gas properties and depreciation of production equipmentwhich includes estimated future development costs less estimated salvage values are calculated using theunit-of-production method, based on production volumes in relation to estimated proven reserves.


UNPROVED PROPERTIES


CEILING TEST

The ceiling test is a cost recovery test intended to identify and measure potential impairment of the value of assetsrelative to the cost of those assets as carried on Altia’s balance sheet. An impairment loss would be recorded if the sumof the undiscounted cash flows (assuming certain commodity prices, operating costs, royalty rates and otherdeductions) expected from the production of the proved reserves and the lower of cost and market of unprovedproperties does not exceed the values of the petroleum and natural gas assets as carried on Altia’s balance sheet. Animpairment loss is recognized to the extent that the carrying value exceeds the sum of the discounted cash flowsexpected from the production of proved and probable reserves and the lower of cost and market of unproved properties.

MDA-23

The cash flows were estimated using the future product prices and costs and were discounted using the risk free rate.By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statementscould be material. Any impairment as a result of this ceiling test would be charged to operations as additional depletionand depreciation expense.

A ceiling test was performed quarterly by Altia and at each testing period, Altia had sufficient value of Altia’sproved and probable reserves under the formula to cover the value of the petroleum and natural gas assets as carried onthe Altia’s balance sheet.

ASSET RETIREMENT OBLIGATIONS

Altia recorded a liability for the fair value of legal obligations associated with the retirement of petroleum andnatural gas assets. The liability was equal to the discounted fair value of the obligation in the period in which the assetwas recorded with an equal offset to the carrying amount of the asset. The liability then accretes to its fair value withthe passage of time and the accretion is recognized as an expense in the financial statements. The total amount of theasset retirement obligation is an estimate based on Altia’s net ownership interest in all wells and facilities, theestimated costs to abandon and reclaim the wells and facilities and the estimated timing of the costs to be incurred infuture periods. The total amount of the estimated cash flows required to settle the asset retirement obligation, thetiming of those cash flows and the discount rate used to calculate the present value of those cash flows were allestimates subject to measurement uncertainty. Any change in these estimates would impact the asset retirement liabilityand the accretion expense.

INCOME TAXES

The determination of income and other tax liabilities requires interpretation of complex laws and regulations. Alltax filings are subject to audit and potential reassessment after the lapse of considerable time. In addition, Altiaestimated when its temporary differences were expected to reverse and recognized its tax assets and liabilities based onthe legislated tax rate in those periods. Accordingly, the actual income tax liability may differ significantly from thatestimated and recorded by management.

STOCK-BASED COMPENSATION

Altia applied the fair value method for valuing stock option grants. This method required Altia to make estimatesof expected stock volatility, the expected hold period prior to exercising options, expected forfeitures of options andexpected dividends to be declared by Altia. The calculation of the fair value of stock-based compensation was notadjusted for the value actually received by the optionees. The stock-based compensation expense would not representthe actual fair value received by the optionees as the fair value is estimated at the time of grant and was not adjusted.Due to the time period and the number of estimates involved, it is likely that the actual value of the options woulddiffer from what has been recorded in the financial statements.

OTHER ESTIMATES

The accrual method of accounting requires management to incorporate certain estimates including estimates ofrevenues, royalties and operating costs as at a specific reporting date, but for which actual revenues and costs have notyet been received. In addition, estimates are made on capital projects which are in progress or recently completedwhere actual costs have not been received by the reporting date. Altia obtained the estimates from the individuals withthe most knowledge of the activity and from all project documentation received. The estimates were reviewed forreasonableness and compared to past performance to assess the reliability of the estimates. Past estimates werecompared to actual results in order to make informed decisions on future estimates.

Disclosure Controls And Procedures

Disclosure controls and procedures were designed by Altia to ensure that information required to be disclosed byAltia was accumulated and communicated to Altia’s management as appropriate to allow timely decisions regardingrequired disclosure.

MDA-24

Business risks and uncertainties

Altia monitored and complied with current government regulations that affected its activities, although operationsmay be adversely affected by changes in government policy, regulations or taxation. In addition, Altia maintained alevel of liability, property and business interruption insurance which was believed to be adequate for Altia’s size andactivities, but was unable to obtain insurance to cover all risks within the business or in amounts to cover all possibleclaims.

Impact of new environmental regulations

Environmental legislation, including the Kyoto Accord, the federal government’s “EcoACTION” plan andAlberta’s Bill 3 – Climate Change and Emissions Management Amendment Act, was evolving in a manner expected toresult in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures andoperating costs. Given the evolving nature of the debate related to climate change and the resulting requirements, it wasnot possible to determine the operational or financial impact of those requirements on Altia at the date of the AltiaQuarterly MD&A.

ACCOUNTING POLICY UPDATES





On April 1, 2008, Altia adopted the new CICA standards, Section 3860 “Financial Instruments – Disclosures andPresentation”. The new disclosure standard increased the emphasis on the risks associated with both recognized andunrecognized financial instruments and how those risks are managed. The new presentation standard carried forwardthe former presentation requirements. This would not impact Altia’s financial statements.

On October 2, 2008, the Accounting Standards Board decided that private enterprises would not be required toapply the following financial instrument standard sections: 1530 “Comprehensive Income,” 3855 “FinancialInstruments – Recognition and Measurement,” 3862 “Financial Instruments – Disclosures,” 3863 “FinancialInstruments – Presentation,” 3865 “Hedges,” and 3251 “Equity.” As Altia was a private enterprise, Altia chose not toadopt these financial instrument standards.



On April 1, 2008, Altia adopted CICA standards, Section 1535 “Capital Disclosures,” which required companiesto disclose their objectives, policies and processes for managing capital. In addition, disclosures were to includewhether companies have complied with externally imposed capital requirements.



In January 2006, the CICA Accounting Standards Board (“AcSB”) adopted a strategic plan for the direction ofaccounting standards in Canada. As part of the plan, accounting standards in Canada for public companies wereexpected to converge with International Financial Reporting Standards (“IFRS”) by the beginning of 2011. In May2009, AcSB released an exposure draft of Generally Accepted Accounting Principles (GAAP) for Private Enterprises.Private companies would have a choice of reporting in accordance with Canadian GAAP by adopting either the sameset of accounting standards as public companies (IFRS) or the proposed standards for private companies (CanadianGAAP for private enterprises). At the date of the Altia Quarterly MD&A Altia was reviewing the requirements of IFRSand Canadian GAAP for private enterprises and expected to adopt one of the new standards by the applicable dates.

MDA-25

QUARTERLY FINANCIAL & OPERATING SUMMARY HIGHLIGHTS

OperationsDec31/09

Sep31/09

Jun30/09

Mar31/09

Dec31/08

Sept30/08

June30/08

Mar31/08

Natural Gas (mcf/d) . . . . . . . . . . . . . . . . . . . . . . 6,576 6,884 8,572 10,131 9,368 7,377 6,021 1,073Natural Gas Liquid Sales (blpd) . . . . . . . . . . . . . 3 8 5 7 8 8 7 10Oil Sales (bopd) . . . . . . . . . . . . . . . . . . . . . . . . . 10 7 11 12 11 10 11 18Total Sales (boepd) . . . . . . . . . . . . . . . . . . . . . . . 1,109 1,162 1,445 1,708 1,580 1,248 1,022 207Natural Gas Price ($/mcf) . . . . . . . . . . . . . . . . . . 4.62 2.90 3.26 5.03 6.67 7.64 10.29 7.95Natural Gas Liquid Price ($/bbl) . . . . . . . . . . . . 67.57 56.22 67.69 29.49 57.43 115.85 109.14 83.89Oil Price ($/bbl) . . . . . . . . . . . . . . . . . . . . . . . . . 74.90 71.74 60.35 48.44 73.63 111.80 120.28 90.91

Financial ($000)

Operating Revenue . . . . . . . . . . . . . . . . . . . . . . . 2,882 1,925 2,636 4,658 5,867 5,370 5,827 998Royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (493) (267) (358) (1,025) (1,250) (1,752) (629) (152)

Net Operating Revenue . . . . . . . . . . . . . . . . . . . . 2,389 1,658 2,278 3,633 4,617 3,618 5,198 846Other Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . — 1 1 (4) (10) — 18 51

Total Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . 2,389 1,659 2,279 3,629 4,607 3,618 5,216 897Operating Expense . . . . . . . . . . . . . . . . . . . . . . . 158 167 246 347 398 357 438 416Transportation Expense . . . . . . . . . . . . . . . . . . . 113 126 167 236 136 154 103 33Interest Expense . . . . . . . . . . . . . . . . . . . . . . . . . 34 28 23 25 — — — —G & A Expense . . . . . . . . . . . . . . . . . . . . . . . . . . 289 278 297 308 206 215 223 209DD & A Expense . . . . . . . . . . . . . . . . . . . . . . . . 1,768 1,801 2,664 3,120 3,072 2,229 2,661 657Stock Based Compensation . . . . . . . . . . . . . . . . 199 21 8 8 8 20 21 20

Total Expense . . . . . . . . . . . . . . . . . . . . . . . . . . 2,561 2,421 3,405 4,044 3,820 2,975 3,446 1,335Income (Loss) Before Tax . . . . . . . . . . . . . . . . . (172) (762) (1,126) (415) 787 643 1,770 (438)Future Income Tax (Recovery) Provision . . . . . — — — — — — — —

Net Income (Loss) . . . . . . . . . . . . . . . . . . . . . . . (172) (762) (1,126) (415) 787 643 1,770 (438)

Capital Program

Capital Expenditure ($000) . . . . . . . . . . . . . . . . . 3,591 1,602 (98) 3,013 7,617 5,437 2,306 5,924Disposition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — (300) — — (509) (91)Gross (Net) Wells . . . . . . . . . . . . . . . . . . . . . . . .Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1(0.2) 2(1.0) 2(0.6) 2(0.9) 3(1.25)Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — — 1(0.18)D & A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 1(0.2) — 1(0.15)

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1(0.2) 2(1.0) 3(0.8) 2(0.9) 5(1.58)

* May not add due to rounding

MDA-26

Altia Energy Ltd.

MANAGEMENT’S DISCUSSION & ANALYSIS

FOR THE YEAR ENDED MARCH 31, 2009

This management’s discussion and analysis (the “Altia Annual MD&A”) is intended to provide additionalinformation on the Company for the year ended March 31, 2009 and should be read in conjunction with the auditedfinancial statements of Altia for the year ended March 31, 2009 (the “Altia Annual Financial Statements”) includedin this prospectus. The financial statements were prepared in accordance with Canadian Generally AcceptedAccounting Principles and are presented in Canadian dollars. The financial statements were reviewed by Altia’s AuditCommittee and approved by Altia’s Board of Directors. Per barrel of oil equivalent amounts (boe or boepd) have beencalculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil (6:1). This Altia AnnualMD&A is dated June 23, 2009.

PRODUCTION

Natural gas was the principal component of production for Altia. Average annual production of natural gasincreased to 8,220 Mcf/d (three months – 10,131 Mcf/d) compared to the prior year average of 1,369 Mcf/d (threemonths – 1,073 Mcf/d). The increase in natural gas production was due to the commencement of production from newwells in the Dawson area of British Columbia. NGL production averaged 7 Bbls/d (three months ended – 7 Bbls/d),and compares to the prior year rate of 13 Bbls/d (three months – 10 Bbls/d), oil production averaged 11 Bbls/d (threemonths – 12 Bbls/d) and compares to 22 Bbls/d (three months – 28 Bbls/d) for the prior year. Total production for theyear using the 6:1 equivalence increased to 1,388 Boe/d (three months – 1,708 Boe/d) compared to the prior year rateof 263 Boe/d (three months – 207 Boe/d). NGL and oil production decreased as a result of natural declines.

Three MonthsEnded

March 31 2009

Three MonthsEnded

March 31 2008Year Ended


March 31 2008

Natural Gas (Mcf/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,131 1,073 8,220 1,369NGL (Bbls/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 10 7 13Crude Oil (Bbls/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 28 11 22

Total (Boe/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,708 207 1,388 263

COMMODITY PRICING & MARKETING

All natural gas, NGL and oil production was sold on the spot market to major purchasers. Altia did not have anylong term contracts or hedges. Natural gas prices varied significantly during the year from a high of $10.29/Mcf in thefirst quarter to a low of $5.03/Mcf in the fourth quarter. Natural gas, NGL and oil prices for the three months endedMarch 31, 2009 weakened significantly to a combined average price of $30.32/Boe from $53.13/Boe for the threemonths ended March 31, 2008.

Three MonthsEnded

March 31 2009

Three MonthsEnded



March 31 2008

Natural Gas ($/Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.03 7.95 7.05 7.39NGL ($/Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29.49 83.89 79.51 73.49Crude Oil ($/Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48.44 90.91 87.13 80.28

Boe ($/Boe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30.32 53.13 42.86 48.76

REVENUE ($000)

Altia’s principal source of revenue was from sales of natural gas, NGL and oil production. Other income wasderived principally from interest on cash balances. Total revenues for the year ended March 31, 2009 of $21,726 (threemonths – $4,654) increased compared to the prior year sales of $4,810 (three months – $1,048) due to higher naturalgas sales volumes and offset by a decrease in the price received for natural gas.

MDA-27

Three MonthsEnded

March 31 2009

Three MonthsEnded

March 31 2008

YearEnded

March 31 2009

YearEnded

March 31 2008

Natural Gas Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,589 776 21,157 3,703NGL Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 75 217 361Crude Oil Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51 146 348 633Other Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4) 51 4 113

Total Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,654 1,048 21,726 4,810

ROYALTY EXPENSE ($000)

Altia royalties were paid principally to the provincial governments of British Columbia and Alberta. The increasein royalty expense for both the three months ended and the year ended March 31, 2009 was attributable to the increasein production revenues.

Three MonthsEnded

March 31, 2009

Three MonthsEnded

March 31, 2008

YearEnded

March 31, 2009

YearEnded

March 31, 2008

Royalties . . . . . . . . . . 1,025 152 4,656 717

OPERATING COST & TRANSPORTATION EXPENSE ($000)

The major portion of Altia’s production was processed in company-owned and operated facilities located in theDawson area of British Columbia. Altia used third party facilities and incurred fees for processing its remaining minorproduction volumes. Altia did not receive any significant fees from other sources for processing/transportation ofproduction volumes through its owned facilities. Operating and transportation/marketing costs increased compared tothe prior year due to higher production volumes. On a unit of production basis, operating costs decreased to $3.04/Boe(three months – $2.21/Boe) compared to prior year costs of $14.28/Boe ($21.84/Boe). The decrease was due to higherproduction volumes from the Dawson property with associated low operating costs.

Three MonthsEnded

March 31, 2009

Three MonthsEnded

March 31, 2008Year Ended


March 31, 2008

Operating Expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 347 416 1,540 1,375Transportation & Sales Expense . . . . . . . . . . . . . . . . . . . 236 33 629 165

Total Expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 583 419 2,169 1,540

GENERAL & ADMINISTRATIVE COSTS ($000)

A portion of the general and administrative costs were capitalized and recorded as capital expense required todevelop and explore for future production properties. The total amount capitalized is noted in the table below.

Three MonthsEnded

March 31, 2009

Three MonthsEnded



March 31, 2008

G & A Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 463 397 1,667 1,465Capitalized G & A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (155) (188) (715) (651)

G & A Expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 308 209 952 814

STOCK-BASED COMPENSATION ($000)

Stock based (non-cash) compensation was calculated using the Black Scholes model as described within the notesto the Altia Annual Financial Statements.

Three MonthsEnded

March 31, 2009

Three MonthsEnded

March 31, 2008

YearEnded

March 31, 2009

YearEnded

March 31, 2008

Stock Based Compensation . . . . . . . . . . . . . . . . . . . . . . . 8 20 57 69

MDA-28

DEPLETION, DEPRECIATION & ACCRETION ($000)

Altia followed the full cost method of accounting as described in the CICA’s accounting guideline AcG-16. Thedepletion expense was prepared utilizing the independent reserve report prepared by Sproule Associates Limited for theyear ended March 31, 2009. An amount of $10,039 for undeveloped land value was excluded from the depletioncalculation. The increase in depletion costs for the three months and year ended March 31, 2009 over the prior yearwas principally due to higher production volumes during the current year. On the basis of barrels of equivalent (Boe)the average rate of depletion for the current year was $21.75/Boe (three months – $19.75/Boe) decreasing from theprior year rate of $30.08/Boe (three months – $3.57/Boe), as drilling and completion activities in the Dawson area ledto reserve increases.

Three MonthsEnded

March 31, 2009

Three MonthsEnded



March 31, 2008

Depletion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,103 68 11,022 2,897Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 3 13 12Accretion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 36 47 52

Total DD & A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,120 657 11,082 2,961

NET INCOME ($000)

Net income for the year ending March 31, 2009 increased with revenue and production increases. Net income forthe three months ending March 31, 2009 increased slightly over the same period in 2008 due to production increases,offset by a large increase in DD&A expense.

Three MonthsEnded

March 31 2009

Three MonthsEnded

March 31 2008

Year EndedMarch 31

2009

Year EndedMarch 31

2008

Net Income (Loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (415) (438) 2,785 (1,326)

TAX POOLS ($000)

The tax pool balances as at March 31, 2009 were as follows and are noted in further detail in the notes to the AltiaAnnual Financial Statements.

Year Ended March 31 2009

Undepreciated Capital Cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,651Canadian Exploration Expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22,473Canadian Development Expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,148Canadian Oil & Gas Property Expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,808ACRI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,177Non Capital Loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,750

Total Pools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46,007

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CAPITAL EXPENDITURES ($000)

Capital expenditures are noted for the various categories of investment. Altia drilled, completed and tied-in 7gross (2.7 net) gas wells during fiscal 2009. One gross (0.2) net well was drilled and abandoned during the fiscal year,

Three MonthsEnded

March 31 2009$M

Three MonthsEnded

March 31 2008$M

Year EndedMarch 31 2009

$M

Year EndedMarch 31 2008

$M

Land Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 633 45 3,399 1,139Geological & Geophysical . . . . . . . . . . . . . . . . . . . . . . . . . (300) 927 952 1,283Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 340 2,930 5,772 7,344Completion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,030 797 2,725 1,675Equipping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,186 1,112 4,808 1,527Capitalized G & A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 155 187 715 651Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (31) (74) 2 (44)

Sub-Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,013 5,924 18,373 13,575Disposition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (300) (91) (809) (5,100)

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,713 5,833 17,564 8,475

CAPITAL RESOURCES AND SHARE CAPITAL

On November 1, 2008, Altia signed a business corporation agreement with the Alberta Treasury Branch to haveits revolving credit facility increased to $9,000,000. Interest on the Revolving Operating Demand Loan was at theAlberta Treasury Branch Prime Rate plus 0.25 percent. This facility was allowed to revolve and fluctuate at Altia’sdiscretion without fixed repayment terms and was subject to an annual review.

The credit facility drawn at the Alberta Treasury Branch at March 31, 2009 was $3.0 million.

At March 31, 2009, Altia had a working capital deficiency plus bank debt of $4.4 million, comprised of $3 millionin bank debt and $3.5 million in accounts payable and accrued liabilities, offset by $2.1 million in accounts receivableand prepaids.

Altia had sufficient liquidity and capital resources to fund its fiscal 2010 exploration and production programthrough its expected cash flow from operations and unutilized credit facilities.

As of March 31, 2009 a total of 41,901,293 common shares had been issued for net proceeds of $41,309,811.

COMMITMENTS

As at March 31, 2009, Altia was committed to a long-term lease for office space of:

YearYear-to-date

($000s)

2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2492010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3322011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3322012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83

996

On November 18, 2008, Altia signed a 5 year contract with Westcoast Energy Inc. for 5 mmcf a day of firmeastbound transmission service commencing approximately November 1, 2009. At March 31, 2009, the fees had notyet been established. As at the date of the Altia Annual MD&A, Altia estimated the undiscounted cost over the 5 yearcontract at $1.2 million.

MDA-30

FINANCIAL RISK MANAGEMENT

Altia’s Board of Directors had overall responsibility for the establishment and oversight of Altia’s riskmanagement framework. Altia’s Board had implemented and monitored compliance with risk management policies.Altia’s risk management policies were established to identify and analyze the risks faced by Altia, to set appropriaterisk limits and controls, and to monitor risks and adherence to market conditions and Altia’s activities.


Financial instruments of Altia consisted mainly of cash and short-term investments, deposits, receivables andpayables and due to the short term nature of each, the fair values approximated their carrying value.

Bank debt bears interest at a floating market rate and accordingly the fair value approximates the carryingvalue.

b) Credit risk

Substantially all of the accounts receivable were with joint venture partners, and oil and gas marketers andwere subject to normal industry credit risks. Receivables from joint venture partners were generally collectedwithin one to three months. Altia attempted to mitigate this risk by entering into transactions with long-standing and reputable organizations and by obtaining partner approval of significant capital expendituresand payment of cash advances wherever possible. Further risk existed with joint venture partners asdisagreements occasionally arose and may increase the potential for non-collection. As at the date of theAltia Annual MD&A, there was no indication that amounts were non-collectible and as such, an allowancewas not set-up. Receivables related to oil and gas marketers were normally collected on the 25th day of themonth following production. To mitigate the risk of these receivables, Altia predominately establishedrelationships with marketers who had strong credit ratings and solid reputations. As at the date of the AltiaAnnual MD&A, Altia had not experienced any issues in collecting from its oil and gas marketers. Theaccounts receivable balance at the end of the period represents Altia’s maximum exposure to credit risk.


Altia was exposed to fluctuations in interest rates on its bank debt in response to changes in market interestrates. At March 31, 2009, the increase or decrease for each one percent change in interest rates amounted toapproximately $7,000 in interest rate expense for the year ended March 31, 2009 (March 31, 2008 - $14,000).

c) Commodity price risk

Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes incommodity prices. All natural gas, NGL and oil production is sold on the spot market to major purchasers.Altia did not have any long term contracts or hedges.


Altia’s objectives when managing capital were to (i) deploy capital to provide an appropriate return oninvestment to its shareholders; (ii) maintain financial flexibility in order to preserve its ability to meetfinancial obligations; and (iii) maintain a capital structure that provides financial flexibility to execute onstrategic acquisitions.

Altia’s strategy was designed to maintain a flexible capital structure consistent with the objectives as statedabove and to respond to changes in economic conditions and the risk characteristics of the underlyingpetroleum and natural gas assets.

Altia considered its capital structure to include share capital, bank debt and working capital. In order tomaintain or adjust its capital structure, Altia could from time to time issue new shares, seek debt financingand adjust its capital spending to manage projected debt levels.

In order to facilitate the management of capital expenditures and projected net debt, Altia prepared annualbudgets which were updated as necessary depending upon varying factors including current and forecastnatural gas and crude oil prices, capital expenditures and general industry conditions. The annual budgetswere approved by Altia’s Board of Directors.

At March 31, 2009, Altia had a negative working capital of $4.4 million which included bank debt of$3 million.

MDA-31

As at the date of the Altia Annual MD&A, Altia’s share capital was not subject to external restrictions. As atthe date of the Altia Annual MD&A Altia had not declared or paid any dividends since the incorporation dateof June 12, 2003 and did not contemplate doing so in the foreseeable future.

APPLICATION OF CRITICAL ACCOUNTING ESTIMATES

The financial statements were prepared in accordance with Canadian Generally Accepted Accounting Principles(“GAAP”). A summary of significant accounting policies is presented in Note 1 to the Altia Annual FinancialStatements. Certain accounting policies require that management make appropriate decisions with respect to theformulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses.Management of Altia reviewed its estimates on a regular basis. The emergence of new information and changedcircumstance may result in actual results or changes to estimated amounts that differ materially from current estimates.The following discussion identifies the critical accounting policies and practices of Altia and helps assess thelikelihood of materially different results being reported.

RESERVES

Under the National Instrument 51-101 (“NI 51-101”), “Proved” reserves are defined as those reserves that can beestimated with a high degree of certainty to be recoverable. The level of certainty should result in at least 90%probability that the quantities actually recovered will equal or exceed the estimated Proved reserves. It does not meanthat there is a 90% probability that the Proved reserves will be recovered; it means there must be at least 90%probability that the given amount or more will be recovered.


These oil and gas reserve estimates are made using all available geological and reservoir data, as well as historicalproduction data. All of Altia’s reserves were evaluated and reported on by independent qualified reserves evaluators.However, revisions can occur as a result of various factors including: actual reservoir performance, changes in priceand cost forecasts or, a change in Altia’s plans. Reserve changes will impact the financial results as reserves are used inthe calculation of depletion and are used to assess whether asset impairment occurs.

DEPLETION AND DEPRECIATION

Altia followed the full cost method of accounting for oil and natural gas properties. Under this method, all costsrelated to the acquisition of, exploration for and development of oil and natural gas reserves are capitalized whethersuccessful or not. Depletion of the capitalized oil and natural gas properties and depreciation of production equipmentwhich includes estimated future development costs less estimated salvage values are calculated using theunit-of-production method, based on production volumes in relation to estimated proven reserves.


UNPROVED PROPERTIES


CEILING TEST

The ceiling test is a cost recovery test intended to identify and measure potential impairment of the value of assetsrelative to the cost of those assets as carried on Altia’s balance sheet. An impairment loss would be recorded if the sumof the undiscounted cash flows (assuming certain commodity prices, operating costs, royalty rates and other

MDA-32

deductions) expected from the production of the proved reserves and the lower of cost and market of unprovedproperties does not exceed the values of the petroleum and natural gas assets as carried in Altia’s balance sheet. Animpairment loss is recognized to the extent that the carrying value exceeds the sum of the discounted cash flowsexpected from the production of proved and probable reserves and the lower of cost and market of unproved properties.The cash flows are estimated using the future product prices and costs and are discounted using the risk free rate. Bytheir nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could bematerial. Any impairment as a result of this ceiling test will be charged to operations as additional depletion anddepreciation expense.

A ceiling test was performed quarterly by Altia and at each testing period, Altia had sufficient value of Altia’sproved and probable reserves under the formula to cover the value of the petroleum and natural gas assets as carried onAltia’s balance sheet.

ASSET RETIREMENT OBLIGATIONS

Altia recorded a liability for the fair value of legal obligations associated with the retirement of petroleum andnatural gas assets. The liability was equal to the discounted fair value of the obligation in the period in which the assetwas recorded with an equal offset to the carrying amount of the asset. The liability then accretes to its fair value withthe passage of time and the accretion is recognized as an expense in the financial statements. The total amount of theasset retirement obligation is an estimate based on Altia’s net ownership interest in all wells and facilities, theestimated costs to abandon and reclaim the wells and facilities and the estimated timing of the costs to be incurred infuture periods. The total amount of the estimated cash flows required to settle the asset retirement obligation, thetiming of those cash flows and the discount rate used to calculate the present value of those cash flows were allestimates subject to measurement uncertainty. Any change in these estimates would impact the asset retirement liabilityand the accretion expense.

INCOME TAXES

The determination of income and other tax liabilities requires interpretation of complex laws and regulations. Alltax filings are subject to audit and potential reassessment after the lapse of considerable time. In addition, Altiaestimated when its temporary differences are expected to reverse and recognized its tax assets and liabilities based onthe legislated tax rate in those periods. Accordingly, the actual income tax liability may differ significantly from thatestimated and recorded by management.

STOCK-BASED COMPENSATION

Altia applied the fair value method for valuing stock option grants. This method required Altia to make estimatesof expected stock volatility, the expected hold period prior to exercising options, expected forfeitures of options andexpected dividends to be declared by Altia. The calculation of the fair value of stock-based compensation was notadjusted for the value actually received by the optionees. The stock-based compensation expense would not representthe actual fair value received by the optionees as the fair value is estimated at the time of grant and was not adjusted.Due to the time period and the number of estimates involved, it is likely that the actual value of the options woulddiffer from what has been recorded in the financial statements.

OTHER ESTIMATES

The accrual method of accounting requires management to incorporate certain estimates including estimates ofrevenues, royalties and operating costs as at a specific reporting date, but for which actual revenues and costs have notyet been received. In addition, estimates are made on capital projects which are in progress or recently completedwhere actual costs have not been received by the reporting date. Altia obtained the estimates from the individuals withthe most knowledge of the activity and from all project documentation received. The estimates were reviewed forreasonableness and compared to past performance to assess the reliability of the estimates. Past estimates werecompared to actual results in order to make informed decisions on future estimates.

MDA-33

Disclosure Controls And Procedures

Disclosure controls and procedures were designed to ensure that information required to be disclosed by Altia wasaccumulated and communicated to Altia’s management as appropriate to allow timely decisions regarding requireddisclosure.

Business risks and uncertainties

Altia monitored and complied with current government regulations that affected its activities, although operationsmay be adversely affected by changes in government policy, regulations or taxation. In addition, Altia maintained alevel of liability, property and business interruption insurance which was believed to be adequate for Altia’s size andactivities, but was unable to obtain insurance to cover all risks within the business or in amounts to cover all possibleclaims.

Impact of new environmental regulations

Environmental legislation, including the Kyoto Accord, the federal government’s “EcoACTION” plan andAlberta’s Bill 3 – Climate Change and Emissions Management Amendment Act, was evolving in a manner expected toresult in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures andoperating costs. Given the evolving nature of the debate related to climate change and the resulting requirements, it wasnot possible to determine the operational or financial impact of those requirements on Altia at the date of the AltiaAnnual MD&A.

ACCOUNTING POLICY UPDATES





On April 1, 2008, Altia adopted the new CICA standards, Section 3860 “Financial Instruments – Disclosures andPresentation”. The new disclosure standard increased the emphasis on the risks associated with both recognized andunrecognized financial instruments and how those risks are managed. The new presentation standard carried forwardthe former presentation requirements. This would not impact Altia’s financial statements.

On October 2, 2008, the Accounting Standards Board decided that private enterprises would not be required toapply the following financial instrument standard sections: 1530 “Comprehensive Income,” 3855 “FinancialInstruments – Recognition and Measurement,” 3862 “Financial Instruments – Disclosures,” 3863 “FinancialInstruments – Presentation,” 3865 “Hedges,” and 3251 “Equity.” As Altia was a private enterprise, Altia chose not toadopt these financial instrument standards.



On April 1, 2008, Altia adopted CICA standards, Section 1535 “Capital Disclosures,” which required companiesto disclose their objectives, policies and processes for managing capital. In addition, disclosures were to includewhether companies have complied with externally imposed capital requirements.

MDA-34



In January 2006, the CICA Accounting Standards Board (“AcSB”) adopted a strategic plan for the direction ofaccounting standards in Canada. As part of the plan, accounting standards in Canada for public companies wereexpected to converge with International Financial Reporting Standards (“IFRS”) by the beginning of 2011. In May2009, AcSB released an exposure draft of Generally Accepted Accounting Principles (GAAP) for Private Enterprises.Private companies would have a choice of reporting in accordance with Canadian GAAP by adopting either the sameset of accounting standards as public companies (IFRS) or the proposed standards for private companies (CanadianGAAP for private enterprises). At the date of the Altia Annual MD&A, Altia was reviewing the requirements of IFRSand Canadian GAAP for private enterprises and expected to adopt one of the new standards by the applicable dates.

MDA-35

FINANCIAL & OPERATING SUMMARY HIGHLIGHTS – YEAR ENDED MARCH 31, 2009

OperationsMar31/09

Dec31/08

Sept30/08

June30/08

Mar31/08

Dec31/07

Sept30/07

June30/07

Natural Gas (mcf/d) . . . . . . . . . . . . . . . . 10,131 9,368 7,377 6,021 1,073 1,170 1,015 2,225Natural Gas Liquid Sales (blpd) . . . . . . 7 8 8 7 10 12 8 24Oil Sales (bopd) . . . . . . . . . . . . . . . . . . . 12 11 10 11 18 19 8 41Total Sales (boepd) . . . . . . . . . . . . . . . . 1,708 1,580 1,248 1,022 207 226 185 436

Natural Gas Price ($/mcf) . . . . . . . . . . . 5.03 6.67 7.64 10.29 7.95 6.75 5.88 8.15Natural Gas Liquid Price ($/bbl) . . . . . . 29.49 57.43 115.85 109.14 83.89 79.61 94.88 58.75Oil Price ($/bbl) . . . . . . . . . . . . . . . . . . . 48.44 73.63 111.80 120.28 90.91 90.88 79.37 70.86

Financial ($000)

Operating Revenue . . . . . . . . . . . . . . . . 4,658 5,867 5,370 5,827 998 977 679 2,043Royalties . . . . . . . . . . . . . . . . . . . . . . . . (1,025) (1,250) (1,752) (629) (152) (193) (130) (242)

Net Operating Revenue . . . . . . . . . . . . . 3,633 4,617 3,618 5,198 846 784 549 1,801Other Revenue . . . . . . . . . . . . . . . . . . . . (4) (10) — 18 51 39 20 3

Total Revenue . . . . . . . . . . . . . . . . . . . 3,629 4,607 3,618 5,216 897 823 569 1,804

Operating Expense . . . . . . . . . . . . . . . . . 347 398 357 438 416 276 208 475Transportation Expense . . . . . . . . . . . . . 236 136 154 103 33 37 31 64Interest Expense . . . . . . . . . . . . . . . . . . . 25 — — — — 5 — 30G & A Expense . . . . . . . . . . . . . . . . . . . 308 206 215 223 209 184 172 249DD & A Expense . . . . . . . . . . . . . . . . . . 3,120 3,072 2,229 2,661 657 589 414 1,301Stock Based Compensation . . . . . . . . . . 8 8 20 21 20 20 14 15

Total Expense . . . . . . . . . . . . . . . . . . . . 4,044 3,820 2,975 3,446 1,335 1,111 839 2,134

Income (Loss) Before Tax . . . . . . . . . . . (415) 787 643 1,770 (438) (288) (270) (330)Future Income Tax (Recovery)

Provision . . . . . . . . . . . . . . . . . . . . . . — — — — — — — —

Net Income (Loss) . . . . . . . . . . . . . . . . (415) 787 643 1,770 (438) (288) (270) (330)

Capital Program

Capital Expenditure ($000) . . . . . . . . . . 3,013 7,617 5,437 2,306 5,924 3,981 3,224 446Disposition . . . . . . . . . . . . . . . . . . . . . . . (300) — — (509) (91) — — (5,009)Gross (Net) Wells . . . . . . . . . . . . . . . . . (0.2)Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1(0.2) 2(1.0) 2(0.6) 2(0.9) 3(1.25) 1(.58) 1(.58) —Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — — 1(0.18) — — —D & A . . . . . . . . . . . . . . . . . . . . . . . . . . — — 1(0.2) — 1(0.15) — 1(1.0) —

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1(0.2) 2(1.0) 3(0.8) 2(0.9) 5(1.58) 1(.58) 2(1.58)

* May not add due to rounding

SELECTED ANNUAL INFORMATION

($M, except production amounts) 2009 2008 2007

Natural Gas (mcf/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,220 1,369 2,876Natural Gas Liquid Sales (blpd) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 13 31Oil Sales (bopd) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 22 32Total Sales (boepd) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,388 263 542

Total revenue, net of royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17,070 3,980 7,474Net earnings (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,785 (1,326) (7,399)Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42,645 39,086 30,557

MDA-36


Management’s Discussion and AnalysisFor the years ended December 31, 2009 and 2008 and for the three months ended March 31, 2010 and 2009

The following management’s discussion and analysis of the results of operations should be read in conjunctionwith the unaudited schedule of revenues, royalties and operating expenses of the Greater Hinton Properties for the threemonths ended March 31, 2010 and 2009 and the audited schedule of revenues, royalties and operating expenses and thenotes thereto for the years ended December 31, 2009 and 2008. This management’s discussion and analysis is datedNovember 15, 2010.


PRODUCTION

The Greater Hinton properties produced 1,515,213 Boe in 2009 (2008 – 916,188 Boe), averaging 4,151 Boe/dcompared to an average rate of 2,510 Boe/d during 2008. Production for the three months ended March 31, 2010averaged 4,590 Boe/d as compared to 3,588 Boe/d for the three months ended March 31, 2009.

REVENUE

Revenues for the year ended December 31, 2009 were $36.1 million compared to $43.8 million for 2008,attributable to lower natural gas prices during 2009 when compared to 2008. Revenue grew from $10.1 million for thethree months ended March 31, 2009 to $12.6 million for the three months ended March 31, 2010 with quarter-over-quarter improvements in the market price of natural gas, combined with production increases.

ROYALTIES

For the year ended December 31, 2009, the average effective royalty rate was 16.6%, compared to 9.4% for 2008.For the three months ended March 31, 2010 the average effective royalty rate was 12.7% compared to 24.2% for thethree months ended March 31, 2009.

OPERATING EXPENSES

Operating expenses for the year ended December 31, 2009 were $7.6 million or $4.99/Boe, compared to $5.8million or $6.37/Boe for the year ended December 31, 2008. Increases in year-over-year production led to a decrease inoperating expenses per Boe from 2009 to 2008. Similarly, operating expenses of $3.20/Boe for the three months endedMarch 31, 2010 fell from $6.50/Boe for the same period in 2009.


Net operating income for 2009 was $22.6 million which decreased from $33.9 million in the prior year. Thisdecrease is due to lower natural gas prices combined with higher operating expenses. There was an increase in netoperating income to $9.6 million for the three months ending March 31, 2009 compared to $5.5 million for the sameperiod in 2008 as natural gas prices strengthened and operating expenses decreased.

MDA-37

APPENDIX “A”

MANDATE OF THE BOARD OF DIRECTORS ANDCORPORATE GOVERNANCE DISCLOSURE

MANDATE OF THE BOARD OF DIRECTORS

General

The Board of Directors (the “Board”) of Tourmaline Oil Corp. (the “Corporation” or “Tourmaline”) isresponsible for the stewardship of the Corporation. In discharging its responsibility, the Board will exercise the care,diligence and skill that a reasonably prudent person would exercise in comparable circumstances and will act honestlyand in good faith with a view to the best interests of Tourmaline. In general terms, the Board will:

Š in consultation with the chief executive officer of the Corporation (the “CEO”), define the principalobjectives of Tourmaline;

Š supervise the management of the business and affairs of Tourmaline with the goal of achieving Tourmaline’sprincipal objectives as developed in association with the CEO;

Š discharge the duties imposed on the Board by applicable laws; and

Š for the purpose of carrying out the foregoing responsibilities, take all such actions as the Board deemsnecessary or appropriate.

Specific

Executive Team Responsibility

Š Appoint the CEO and senior officers, approve their compensation, and monitor the CEO’s performanceagainst a set of mutually agreed corporate objectives directed at maximizing shareholder value.

Š In conjunction with the CEO, develop a clear mandate for the CEO, which includes a delineation ofmanagement’s responsibilities.

Š Establish processes as required that adequately provides for succession planning, including the appointing,training and monitoring of senior management.

Š Establish limits of authority delegated to management.

Operational Effectiveness and Financial Reporting

Š Annual review and adoption of a strategic planning process and approval of Tourmaline’s strategic plan,which takes into account, among other things, the opportunities and risks of the business.

Š Establish or cause to be established systems to identify the principal risks to Tourmaline and that the bestpractical procedures are in place to monitor and mitigate the risks.

Š Establish or cause to be established processes to address applicable regulatory, corporate, securities and othercompliance matters.

Š Establish or cause to be established an adequate system of internal control.

Š Establish or cause to be established due diligence processes and appropriate controls with respect toapplicable certification requirements regarding Tourmaline’s financial and other disclosure.

Š Review and approve Tourmaline’s financial statements and oversee Tourmaline’s compliance withapplicable audit, accounting and reporting requirements.

Š Approve annual operating and capital budgets.

Š Review and consider for approval all amendments or departures proposed by management from establishedstrategy, capital and operating budgets.

Š Review operating and financial performance results relative to established strategy, budgets and objectives.

Integrity/Corporate Conduct

Š Establish a communications policy or policies to ensure that a system for corporate communications to allstakeholders exists, including processes for consistent, transparent, regular and timely public disclosure, andto facilitate feedback from stakeholders.

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Š Approve a Business Conduct & Ethics Practice for directors, officers and employees and monitor compliancewith the Practice and approve any waivers of the Practice for officers and directors.

Š To the extent feasible, satisfy itself as to the integrity of the CEO and other executive officers of theCorporation and that the CEO and other executive officers create a culture of integrity throughoutTourmaline.

Board Process/Effectiveness

Š Attempt to ensure that Board materials are distributed to directors in advance of regularly scheduledmeetings to allow for sufficient review of the materials prior to the meeting. Directors are expected to attendall meetings.

Š Engage in the process of determining Board member qualifications with the Corporate GovernanceCommittee including ensuring that a majority of directors qualify as independent directors pursuant toNational Instrument 58-101 Disclosure of Corporate Governance Practices (as implemented by the CanadianSecurities Administrators and as amended from time to time) and that the appropriate number of independentdirectors are on each committee of the Board as required under applicable securities rules and requirements.

Š Approve the nomination of directors.

Š Provide a comprehensive orientation to each new director.

Š Establish an appropriate system of corporate governance including practices to ensure the Board functionsindependently of management.

Š Establish appropriate practices for the regular evaluation of the effectiveness of the Board, its committeesand its members.

Š Establish committees and approve their respective mandates and the limits of authority delegated to eachcommittee.

Š Review and re-assess the adequacy of the mandate of the committees of the Board on a regular basis, but notless frequently than on an annual basis.

Š Review the adequacy and form of the directors’ compensation to ensure it realistically reflects theresponsibilities and risks involved in being a director.

Each member of the Board is expected to understand the nature and operations of Tourmaline’s business, andhave an awareness of the political, economic and social trends prevailing in all countries or regions in whichTourmaline operates, or is contemplating potential operations.

Independent directors shall meet regularly, and in no case less frequently than quarterly, without non-independentdirectors and management participation.

The Board may retain persons having special expertise and may obtain independent professional advice to assist itin fulfilling its responsibilities at the expense of the Corporation, as determined by the Board.

In addition to the above, adherence to all other Board responsibilities as set forth in the Corporation’s By-Laws,applicable policies and practices and other statutory and regulatory obligations, such as issuance of securities, etc., isexpected.

Delegation

Š The Board may delegate its duties to, and receive reports and recommendations from, any committee of theBoard.

Š Subject to terms of the Disclosure, Confidentiality and Trading Policy and other policies and procedures ofTourmaline, the Chairman of the Board will act as a liaison between stakeholders of Tourmaline and theBoard (including independent members of the Board).

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CORPORATE GOVERNANCE DISCLOSURE

The prescribed corporate governance disclosure for the Company is that contained in Form 58-101F1 which isattached to NI 58-101 (“Form 58-101F1 Disclosure”).

Set out below is a description of the Company’s current corporate governance practices, relative to theForm 58-101F1 Disclosure.

1. Board of Directors

(a) Disclose the identity of directors who are independent.

The following three directors of the Company are independent (for purposes of NI 58-101):

William D. Armstrong;Robert W. Blakely; andPhillip A. Lamoreaux.

(b) Disclose the identity of directors who are not independent, and describe the basis for thatdetermination.

Michael L. Rose is not independent as he also occupies the position of President and CEO.

Robert N. Yurkovich is not independent as he also occupies the position of Executive Vice President,Exploration.

Brian G. Robinson is not independent as he also occupies the position of Vice President, Finance and CFO.

Kevin Keenan is not independent as he was within the last three years an employee and executive officer ofExshaw, a subsidiary of the Company.

Clayton H. Riddell is not independent as he is the father-in-law of the President and CEO of the Company.

(c) Disclose whether or not a majority of directors are independent. If a majority of directors are notindependent, describe what the board of directors (the board) does to facilitate its exercise ofindependent judgement in carrying out its responsibilities.

A majority of the directors of the Company (5 of the 8) are not independent. See also paragraph 1(e) below.

(d) If a director is presently a director of any other issuer that is a reporting issuer (or the equivalent) in ajurisdiction or a foreign jurisdiction, identify both the director and the other issuer.

The following directors are directors of other issuers that are reporting issuers (or the equivalent):

Name of Director Name of Other Reporting Issuers

Clayton H. Riddell Alaris Royalty Corp., MGM Energy Corp.,Perpetual Energy Inc., Paramount ResourcesLtd., Trilogy Energy Corp., Big RockBrewery Income Trust, Newalta Corporationand Sonde Resources Corp.

Robert Blakely Denninghouse Inc.

(e) Disclose whether or not the independent directors hold regularly scheduled meetings at whichnon-independent directors and members of management are not in attendance. If the independentdirectors hold such meetings, disclose the number of meetings held since the beginning of the issuer’smost recently completed financial year. If the independent directors do not hold such meetings,describe what the board does to facilitate open and candid discussion among its independent directors.

At the end of or during each meeting of the Board, the members of management of the Company and themanagement directors of the Company who are present at such meeting leave the meeting in order for theindependent directors to meet separately. Three of such meetings of the independent directors have been heldsince the beginning of the Company’s most recently completed financial year. In addition, other meetings ofthe independent directors may be held from time to time if required.

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(f) Disclose whether or not the chair of the board is an independent director. If the board has a chair orlead director who is an independent director, disclose the identity of the independent chair or leaddirector, and describe his or her role and responsibilities. If the board has neither a chair that isindependent nor a lead director that is independent, describe what the board does to provideleadership for its independent directors.

The Chairman of the Board is not an independent director. Tourmaline’s independent directors each play animportant leadership role on the Board and as a result the Board is of the view that an independent chair orindependent lead director is not required for Tourmaline at the present time.

(g) Disclose the attendance record of each director for all board meetings held since the beginning of theissuer’s most recently completed financial year.

The attendance record of each of the directors of the Company for meetings and committee meetings held in2009, subsequent to their appointment, is as follows:

NameBoard MeetingsAttended / Held

AuditCommitteeMeetingsAttended/ Held

Reserves, Safetyand

EnvironmentalCommitteeMeetings

Attended / Held

Michael L. Rose(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2/2 4/4

William D. Armstrong . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2/2 1/1

Robert W. Blakely . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2/2 4/4

Kevin Keenan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2/2 4/4 1/1

Phillip A. Lamoreaux(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2/2

Clayton H. Riddell . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2/2

Brian G. Robinson . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2/2

Robert N. Yurkovich . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2/2

(1) Mr. Rose was replaced as a member of the Audit Committee on September 9, 2010 by Mr. Lamoreaux.(2) Mr. Lamoreaux was appointed to the Board on September 9, 2010.(3) No meetings of the Compensation Committee or Corporate Governance Committee were held in 2009.

2. Board Mandate – Disclose the text of the board’s written mandate. If the board does not have a writtenmandate, describe how the board delineates its role and responsibilities.

The mandate of the board is set forth above.

3. Position Descriptions

(a) Disclose whether or not the board has developed written position descriptions for the chair and thechair of each board committee. If the board has not developed written position descriptions for thechair and/or the chair of each board committee, briefly describe how the board delineates the role andresponsibilities of each such position.

The Board of Directors has developed written position descriptions for the Chairman of the Board as well asthe Chairman of each of the committees of the Board.

(b) Disclose whether or not the board and CEO have developed a written position description for theCEO. If the board and CEO have not developed such a position description, briefly describe how theboard delineates the role and responsibilities of the CEO.

The Board, with the input of the CEO of the Company, has developed a written position description for theCEO.

4. Orientation and Continuing Education

(a) Briefly describe what measures the board takes to orient new directors regarding (i) the role of theboard, its committees and its directors, and (ii) the nature and operation of the issuer’s business.

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As new directors join the Board, they are provided with, among other things, corporate policies, historicalinformation about the Company, information on the Company’s performance and its strategic plan and anoutline of the general duties and responsibilities entailed in carrying out their duties.

(b) Briefly describe what measures, if any, the board takes to provide continuing education for itsdirectors. If the board does not provide continuing education, describe how the board ensures that itsdirectors maintain the skill and knowledge necessary to meet their obligations as directors.

The Company encourages directors to attend, enrol or participate in courses and/or seminars dealing withfinancial literacy, corporate governance and related matters. Each director of the Company has theresponsibility for ensuring that he or she maintains the skill and knowledge necessary to meet his or herobligations as a director.

5. Ethical Business Conduct

(a) Disclose whether or not the board has adopted a written code for the directors, officers and employees.If the board has adopted a written code:

The Company has adopted a Code of Business Conduct and Ethics for directors, officers and employees (the“Code”). In addition, the Company has adopted a separate Code of Ethics for Senior Officers.

(i) disclose how a person or company may obtain a copy of the code;

A copy of the Code may be obtained from the Secretary of the Company, (403) 266-5992 and will beavailable on SEDAR at www.sedar.com following Closing.

(ii) describe how the board monitors compliance with its code, or if the board does not monitorcompliance, explain whether and how the board satisfies itself regarding compliance with its code;and

The Board monitors compliance with the Code by requiring that each of the officers, employees andconsultants of the Company affirm in writing on an annual basis his or her agreement to abide by theCode. In addition, management provides reports on compliance with the Code to the Board on a regularbasis.

(iii) provide a cross-reference to any material change report filed since the beginning of the issuer’smost recently completed financial year that pertains to any conduct of a director or executiveofficer that constitutes a departure from the code.

Not applicable.

(b) Describe any steps the board takes to ensure directors exercise independent judgement in consideringtransactions and agreements in respect of which a director or executive officer has a material interest.

In accordance with the ABCA, directors who are a party to, or are a director or an officer of a person which isa party to, a material contract or material transaction or a proposed material contract or proposed materialtransaction with the Company are required to disclose the nature and extent of their interest and not to voteon any resolution to approve the contract or transaction. In addition, in certain cases, an independentcommittee of the Board may be formed to deliberate on such matters in the absence of the interested party.

(c) Describe any other steps the board takes to encourage and promote a culture of ethical businessconduct.

In addition to the Code, the Board has adopted a “Whistleblower Policy” which provides employees andconsultants of the Company with a mechanism by which they may raise concerns including (but not limitedto) falsification of financial records, unethical conduct, harassment and theft in a confidential, anonymousprocess.

6. Nomination of Directors

(a) Describe the process by which the board identifies new candidates for board nomination.

The Corporate Governance Committee is responsible for recommending suitable candidates for nominees forelection or appointment as director, and recommending the criteria governing the overall composition of theBoard and governing the desirable characteristics for directors. In making such recommendations, theCorporate Governance and Compensation Committee considers: (i) the competence and skills that the Board

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considers to be necessary for the Board, as a whole, to possess; (ii) the competence and skills that the Boardconsiders each existing director to possess; (iii) the competencies and skills that each new nominee will bringto the Board; and (iv) whether or not each new nominee can devote sufficient time and resources to his or herduties as a member of the Board.

The Corporate Governance Committee also reviews on a periodic basis the composition of the Board, andanalyzes the needs of the Board and recommend nominees who meet such needs.

(b) Disclose whether or not the board has a nominating committee composed entirely of independentdirectors. If the board does not have a nominating committee composed entirely of independentdirectors, describe what steps the board takes to encourage an objective nomination process.

The Corporate Governance Committee, which is responsible for nominating directors, is comprised of onenon-independent and two independent directors. The Corporate Governance Committee believes it functionsand continues to function with a non-independent committee member in encouraging an objectivenominating process as the Corporate Governance Committee may engage outside advisors at the expense ofthe Company in appropriate circumstances.

(c) If the board has a nominating committee, describe the responsibilities, powers and operation of thenominating committee.

See item 6(a) above.

7. Compensation

(a) Describe the process by which the board determines the compensation for the issuer’s directors andofficers.

See “Executive Compensation” in the prospectus.

(b) Disclose whether or not the board has a compensation committee composed entirely of independentdirectors. If the board does not have a compensation committee composed entirely of independentdirectors, describe what steps the board takes to ensure an objective process for determining suchcompensation.

The Compensation Committee is comprised of one non-independent and two independent directors.

The Compensation Committee believes it functions with a non-independent committee member in ensuringan objective process for determining compensation as the Compensation Committee may engage outsideadvisors at the expense of the Company in appropriate circumstances.

(c) If the board has a compensation committee, describe the responsibilities, powers and operation of thecompensation committee.

The Compensation Committee’s responsibility is to formulate and make recommendations to the Board inrespect of compensation issues relating to directors and employees of the Company. Without limiting thegenerality of the foregoing, the Governance and Compensation Committee has the following duties:

(i) to review the compensation philosophy and remuneration policy for employees of the Company and torecommend to the Board changes to improve the Company’s ability to recruit, retain and motivateemployees;

(ii) to review and recommend to the Board the retainer and fees to be paid to members of the Board;

(iii) to review and approve corporate goals and objectives relevant to the compensation of the CEO, evaluatethe CEO’s performance in light of those corporate goals and objectives, and determine (or makerecommendations to the Board with respect to) the CEO’s compensation level based on such evaluation;

(iv) to recommend to the Board non CEO officer and director compensation including to reviewmanagement’s recommendations for proposed share option and other incentive compensation plans andequity based plans for non CEO officer and director compensation and make recommendations inrespect thereof to the Board;

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(v) to administer the share option plan approved by the Board in accordance with its terms including therecommendation to the Board of the grant of share options in accordance with the terms thereof;

(vi) to determine and recommend for approval of the Board bonuses to be paid to officers and employees ofthe Company and to establish targets or criteria for the payment of such bonuses, if appropriate; and

(vii) to prepare and submit a report of the Committee for inclusion of annual disclosure required byapplicable securities laws to be made by the Company including the Governance and CompensationCommittee Report required to be included in the information circular – proxy statement of the Companyand review other executive compensation disclosure before the Company publicly discloses suchinformation.

The Compensation Committee is required to be comprised of at least three directors, or such greater numberas the Board may determine from time to time. Two members of the Committee are required to beindependent; as such term is defined for this purpose under applicable securities requirements.

(d) If a compensation consultant or advisor has, at any time since the beginning of the issuer’s mostrecently completed financial year, been retained to assist in determining compensation for any of theissuer’s directors and officers, disclose the identity of the consultant or advisor and briefly summarizethe mandate for which they have been retained. If the consultant or advisor has been retained toperform any other work for the issuer, state that fact and briefly describe the nature of the work.

A compensation consultant has not, at any time since the beginning of the Company’s most recentlycompleted financial year, been retained to assist in determining compensation for any of the Company’sdirectors and officers.

8. Other Board Committees – If the board has standing committees other than the audit, compensation andnominating committees identify the committees and describe their function.

The Company has established a Corporate Governance Committee and a Reserves, Safety and EnvironmentalCommittee.

The Governance Committee’s mandate includes reviewing and recommending mandates of the Board and itscommittees, recommending appropriate governance processes, policies and guidelines for the Company, andformulating and recommending to the Board compensation policies and remuneration for employees, officers anddirectors.

The Reserves, Safety and Environmental Committee’s mandate includes reviewing and overseeing the Company’sprocedures for reserve evaluation and reporting, engaging the independent reserve evaluator and reviewingfundamental policies pertaining to environmental, health and safety.

9. Assessments – Disclose whether or not the board, its committees and individual directors are regularlyassessed with respect to their effectiveness and contribution. If assessments are regularly conducted,describe the process used for the assessments. If assessments are not regularly conducted, describe how theboard satisfies itself that the board, its committees, and its individual directors are performing effectively.

The Board, its committees and individual directors are assessed annually with respect to their effectiveness andcontribution. This is done through structured interviews with board and committee member. The results of theseinterviews for the Board and each director are compiled by the Chairperson of the Governance Committee anddiscussed with the Chairman of the Board after which they are communicated to the entire Board. The results ofthe individual committee interviews are compiled by the Chairperson of that committee and discussed with theChairman of the Board after which they are communicated to the entire Board.

The Corporate Governance Committee, with the participation of the Chairman, may recommend changes toenhance Board performance based on these communications as well as based on its review and assessment of theBoard structure and individuals in relation to current industry and regulatory expectations. This methodology hasbeen both responsive and practical.

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APPENDIX “B”

AUDIT COMMITTEE MANDATE AND AUDIT COMMITTEE DISCLOSURE

AUDIT COMMITTEE MANDATE

Role and Objective

The Audit Committee (the “Committee”) is a committee of the board of directors (the “Board”) of TourmalineOil Corp. (“Tourmaline” or the “Corporation”) to which the Board has delegated its responsibility for the oversightof the following:

1. nature and scope of the annual audit;

2. the oversight of management’s reporting on internal accounting standards and practices;

3. the review of financial information, accounting systems and procedures;

4. financial reporting and financial statements,

and has charged the Committee with the responsibility of recommending, for approval of the Board, the auditedfinancial statements, interim financial statements and other mandatory disclosure releases containing financialinformation.

The primary objectives of the Committee are as follows:

1. To assist directors of Tourmaline (“Directors”) in meeting their responsibilities (especially for accountability) inrespect of the preparation and disclosure of the financial statements of the Corporation and related matters;

2. To provide better communication between Directors and external auditors;

3. To enhance the external auditor’s independence;

4. To increase the credibility and objectivity of financial reports; and

5. To strengthen the role of the outside Directors by facilitating in depth discussions between Directors on theCommittee, management of Tourmaline (“Management”) and external auditors.

Membership of Committee

1. The Committee will be comprised of at least three (3) Directors or such greater number as the Board maydetermine from time to time and all members of the Committee shall be “independent” (as such term is used inNational Instrument 52-110 – Audit Committees (“NI 52-110”) unless the Board determines that the exemptioncontained in NI 52-110 is available and determines to rely thereon.

2. The Board may from time to time designate one of the members of the Committee to be the Chair of theCommittee.

3. All of the members of the Committee must be “financially literate” (as defined in NI 52-110) unless the Boarddetermines that an exemption under NI 52-110 from such requirement in respect of any particular member isavailable and determines to rely thereon in accordance with the provisions of NI 52-110.

Mandate and Responsibilities of Committee

It is the responsibility of the Committee to:

1. Oversee the work of the external auditors, including the resolution of any disagreements between Managementand the external auditors regarding financial reporting.

2. Satisfy itself on behalf of the Board with respect to Tourmaline’s internal control systems identifying, monitoringand mitigating business risks; and ensuring compliance with legal, ethical and regulatory requirements.

3. Review the annual and interim financial statements of the Corporation and related management’s discussion andanalysis (“MD&A”) prior to their submission to the Board for approval. The process should include but not belimited to:

Š reviewing changes in accounting principles and policies, or in their application, which may have a materialimpact on the current or future years’ financial statements;

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Š reviewing significant accruals, reserves or other estimates such as the ceiling test calculation;

Š reviewing accounting treatment of unusual or non-recurring transactions;

Š ascertaining compliance with covenants under loan agreements;

Š reviewing disclosure requirements for commitments and contingencies;

Š reviewing adjustments raised by the external auditors, whether or not included in the financial statements;

Š reviewing unresolved differences between Management and the external auditors; and

Š obtain explanations of significant variances with comparative reporting periods.

4. Review the financial statements, prospectuses, MD&A, annual information forms (“AIF”) and all publicdisclosure containing audited or unaudited financial information (including, without limitation, annual and interimpress releases and any other press releases disclosing earnings or financial results) before release and prior toBoard approval. The Committee must be satisfied that adequate procedures are in place for the review ofTourmaline’s disclosure of all other financial information and will periodically assess the accuracy of thoseprocedures.

5. With respect to the appointment of external auditors by the Board:

Š recommend to the Board the external auditors to be nominated;

Š recommend to the Board the terms of engagement of the external auditor, including the compensation of theauditors and a confirmation that the external auditors will report directly to the Committee;

Š on an annual basis, review and discuss with the external auditors all significant relationships such auditorshave with the Corporation to determine the auditors’ independence;

Š when there is to be a change in auditors, review the issues related to the change and the information to beincluded in the required notice to securities regulators of such change; and

Š review and pre-approve any non-audit services to be provided to Tourmaline or its subsidiaries by theexternal auditors and consider the impact on the independence of such auditors. The Committee may delegateto one or more independent members the authority to pre–approve non–audit services, provided that themember(s) report to the Committee at the next scheduled meeting such pre–approval and the member(s)comply with such other procedures as may be established by the Committee from time to time.

6. Review with external auditors (and internal auditor if one is appointed by Tourmaline) their assessment of theinternal controls of Tourmaline, their written reports containing recommendations for improvement, andManagement’s response and follow-up to any identified weaknesses. The Committee will also review annuallywith the external auditors their plan for their audit and, upon completion of the audit, their reports upon thefinancial statements of Tourmaline and its subsidiaries.

7. Review risk management policies and procedures of the Corporation (i.e., hedging, litigation and insurance).

8. Establish a procedure for:

Š the receipt, retention and treatment of complaints received by Tourmaline regarding accounting, internalaccounting controls or auditing matters; and

Š the confidential, anonymous submission by employees of Tourmaline of concerns regarding questionableaccounting or auditing matters.

9. Review and approve Tourmaline’s hiring policies regarding partners and employees and former partners andemployees of the present and former external auditors of the Corporation.

The Committee has authority to communicate directly with the internal auditors (if any) and the external auditors of theCorporation. The Committee will also have the authority to investigate any financial activity of Tourmaline. Allemployees of Tourmaline are to cooperate as requested by the Committee.

The Committee may also retain persons having special expertise and/or obtain independent professional advice toassist in filling their responsibilities at such compensation as established by the Committee and at the expense ofTourmaline without any further approval of the Board.

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Meetings and Administrative Matters

1. At all meetings of the Committee every resolution shall be decided by a majority of the votes cast. In case of anequality of votes, the Chairman of the meeting shall be entitled to a second or casting vote.

2. The Chair will preside at all meetings of the Committee, unless the Chair is not present, in which case themembers of the Committee that are present will designate from among such members the Chair for purposes ofthe meeting.

3. A quorum for meetings of the Committee will be a majority of its members, and the rules for calling, holding,conducting and adjourning meetings of the Committee will be the same as those governing the Board unlessotherwise determined by the Committee or the Board.

4. Meetings of the Committee should be scheduled to take place at least four times per year. Minutes of all meetingsof the Committee will be taken. The Chief Financial Officer of Tourmaline will attend meetings of the Committee,unless otherwise excused from all or part of any such meeting by the Chairman.

5. The Committee will meet with the external auditor at least once per year (in connection with the preparation of theyear-end financial statements) and at such other times as the external auditor and the Committee considerappropriate.

6. Agendas, approved by the Chair, will be circulated to Committee members along with background information ona timely basis prior to the Committee meetings.

7. The Committee may invite such officers, directors and employees of the Corporation and its subsidiaries as it seesfit from time to time to attend at meetings of the Committee and assist in the discussion and consideration of thematters being considered by the Committee.

8. Minutes of the Committee will be recorded and maintained and circulated to Directors who are not members ofthe Committee or otherwise made available at a subsequent meeting of the Board.

9. The Committee may retain persons having special expertise and may obtain independent professional advice toassist in fulfilling its responsibilities at the expense of the Corporation as determined by the Committee.

10. Any members of the Committee may be removed or replaced at any time by the Board and will cease to be amember of the Committee as soon as such member ceases to be a Director. The Board may fill vacancies on theCommittee by appointment from among its members. If and whenever a vacancy exists on the Committee, theremaining members may exercise all its powers so long as a quorum remains. Subject to the foregoing, followingappointment as a member of the Committee each member will hold such office until the Committee isreconstituted.

11. Any issues arising from these meetings that bear on the relationship between the Board and Management shouldbe communicated to the Chairman of the Board by the Committee Chair.

AUDIT COMMITTEE DISCLOSURE

Audit Committee Mandate and Terms of Reference

The Board has adopted a written mandate and terms of reference for the Audit Committee, which sets out theAudit Committee’s responsibility for (among other things) reviewing the Company’s financial statements and theCompany’s public disclosure documents containing financial information and reporting on such review to the Board,ensuring the Company’s compliance with legal and regulatory requirements, overseeing qualifications, engagement,compensation, performance and independence of the Company’s external auditors, and reviewing, evaluating andapproving the internal control and risk management systems that are implemented and maintained by management. Acopy of the Audit Committee mandate and terms of reference is set forth above.

Composition of the Audit Committee and Relevant Education and Experience

The Audit Committee consists of Messrs. Blakely (Chair), Keenan and Lamoreaux. Each of the members of theAudit Committee is considered “financially literate” and each of Messrs. Blakely and Lamoreaux is considered“independent” within the meaning of NI 52–110. Mr. Keenan is not independent as he was within the last three yearsan employee and executive officer of Exshaw, a subsidiary of the Company. The Board has determined that theexemption in Section 3.2(2) of NI 52–110 is available and has determined to rely thereon. In that connection, the

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Board has determined that reliance on the exemption will not materially adversely affect the ability of the AuditCommittee to act independently and to satisfy the other requirements of NI 52–110. The exemption in Section 3.2(2) ofNI 52–110 relieves an issuer for a period of up to one year after it becomes a reporting issuer from the requirement thatevery audit committee member be independent, provided that a majority of the audit committee members areindependent and the issuer’s board of directors makes the determination in the preceding sentence.

The Company believes that each of the members of the Audit Committee possesses: (a) an understanding of theaccounting principles used by the Company to prepare its financial statements; (b) the ability to assess the generalapplication of such accounting principles in connection with the accounting for estimates, accruals and reserves;(c) experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level ofcomplexity of accounting issues that are generally comparable to the breadth and complexity of issues that canreasonably be expected to be raised by the Company’s financial statements, or experience actively supervising one ormore individuals engaged in such activities; and (d) an understanding of internal controls and procedures for financialreporting. For a summary of the education and experience of each member of the Audit Committee that is relevant tothe performance of his responsibilities as a member of the Audit Committee, see “Directors and Executive Officers –Biographies”.

Pre–Approval Polices and Procedures for the Engagement of Non–Audit Services

The Audit Committee is expected to adopt specific policies and procedures for the engagement of non–auditservices, as described in the mandate of the Audit Committee.

External Audit Service Fees

The following table summarizes the fees paid by the Company and its subsidiaries to its auditors, KPMG LLP, forexternal audit and other services during the periods indicated.

Year Audit Fees(1) Audit - Related Fees(2) Tax Fees(3) All Other Fees(4)

($) ($) ($) ($)

2009 . . . . . . . . . . . . . . . 327,500 185,000 8,000 —

2008 . . . . . . . . . . . . . . . 25,000 — 3,600 —

Notes:(1) Represents the aggregate fees billed by the Company’s external auditor in each of the last two fiscal years for audit services.(2) Represents the aggregate fees billed in each of the last two fiscal years by the Company’s external auditor for assurance and related services that

are reasonably related to the performance of the audit or review of the Company’s financial statements (and not reported under the heading“Audit Fees”). The services comprising the fees disclosed under this category consisted of the conduct of due diligence procedures in connectionwith financings and acquisitions undertaken by the Company.

(3) Represents the aggregate fees billed in each of the last two fiscal years by the Company’s external auditor for professional services for taxcompliance, tax advice and tax planning. The services comprising the fees disclosed under this category consisted of tax consultations and taxcompliance services.

(4) Represents the aggregate fees billed in each of the last two fiscal years by the Company’s external auditor for products and services not includedunder the headings “Audit Fees”, “Audit Related Fees” and “Tax Fees”.

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APPENDIX “C”

FORM 51-101F2REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATORS –

TOURMALINE RESERVES

To the board of directors of Tourmaline Oil Corp. (the “Company”):

1. We have prepared an evaluation of the Company’s reserves data as at December 31, 2009. The reserves data areestimates of proved reserves and probable reserves and related future net revenue as at December 31, 2009,estimated using forecast prices and costs.

2. The reserves data are the responsibility of the Company’s management. Our responsibility is to express an opinionon the reserves data based on our evaluation.

We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas EvaluationHandbook (the “COGE Handbook”) prepared jointly by the Society of Petroleum Evaluation Engineers (CalgaryChapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

3. Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether thereserves data are free of material misstatement. An evaluation also includes assessing whether the reserves dataare in accordance with principles and definitions in the COGE Handbook.

4. The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed toproved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10percent, included in the reserves data of the Company evaluated by us for the year ended December 31, 2009, andidentifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to theCompany’s board of directors:

Independent QualifiedReserves Evaluator

Description andPreparation Date of

EvaluationReport

Location ofReserves (Country or

Foreign Geographic Area)

Net Present Value of Future Net Revenue(before income taxes, 10% discount rate)

Audited Evaluated Reviewed Total

M$ M$ M$ M$

GLJ Petroleum Consultants April 9, 2010 Canada — 581,057 — 581,057

5. In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined andare in accordance with the COGE Handbook. We express no opinion on the reserves data that we reviewed but didnot audit or evaluate.

6. We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurringafter their respective preparation dates.

7. Because the reserves data are based on judgements regarding future events, actual results will vary and thevariations may be material. However, any variations should be consistent with the fact that reserves arecategorized according to the probability of their recovery.

EXECUTED as to our report referred to above.

GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, April 21, 2010.

ORIGINALLY SIGNED BY

Jodi L. Anhorn M.Sc., P. Eng.Vice-President

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APPENDIX “D”

FORM 51-101F3REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE –

TOURMALINE RESERVES

Management of Tourmaline Oil Corp. (the “Company”) are responsible for the preparation and disclosure ofinformation with respect to the Company’s oil and gas activities in accordance with securities regulatory requirements.This information includes reserves data which are estimates of proved reserves and probable reserves and related futurenet revenue as at December 31, 2009, estimated using forecast prices and costs.

An independent qualified reserves evaluator has evaluated the Company’s reserves data. The report of theindependent qualified reserves evaluator is presented below.

The Reserves Committee of the board of directors of the Company has

(a) reviewed the Company’s procedures for providing information to the independent qualified reservesevaluator;

(b) met with the independent qualified reserves evaluator to determine whether any restrictions affected theability of the independent qualified reserves evaluator to report without reservation; and

(c) reviewed the reserves data with management and the independent qualified reserves evaluator.

The Reserves Committee of the board of directors has reviewed the Company’s procedures for assembling andreporting other information associated with oil and gas activities and has reviewed that information with management.The board of directors has approved

(a) the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data andother oil and gas information;

(b) the filing of Form 51-102F2 which is the report of the independent qualified reserves evaluator on thereserves data; and

(c) the content and filing of this report.

Because the reserves data are based on judgments regarding future events, actual results will vary and thevariations may be material. However, any variations should be consistent with the fact that the reserves are categorizedaccording to the probability of their recovery.

DATED as of this 13th day of October, 2010.

(signed) “Michael L. Rose” (signed) “Brian G. Robinson”

Michael L. Rose Brian G. RobinsonPresident, Chief Executive Officer and Director Vice President, Finance and Chief Financial Officer

(signed) “Robert W. Blakely” (signed) “Phillip A. Lamoreaux”

Robert W. Blakely Phillip A. Lamoreaux-Director Director

D-1

APPENDIX “E”

FORM 51-101F2REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATORS –

EXSHAW RESERVES

To the Board of Directors of Exshaw Oil Corp. (the “Company”):

1. We have evaluated the Company’s reserves data as at December 31, 2009. The reserves data are estimates ofproved reserves and related future net revenue as at December 31, 2009, estimated using forecast prices and costs.

2. The reserves data are the responsibility of the Company’s management. Our responsibility is to express an opinionon the reserves data based on our evaluation.

We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas EvaluationHandbook (the “COGE Handbook”) prepared jointly by the Society of Petroleum Evaluation Engineers (CalgaryChapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

3. Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether thereserves data are free of material misstatement. An evaluation also includes assessing whether the reserves dataare in accordance with principles and definitions presented in the COGE Handbook.

4. The following table sets forth the estimated future net revenue (before deduction of income taxes) attributedto proved plus probable reserves, estimated using forecast prices and costs and calculated using a discountrate of 10 percent, included in the reserves data of the Company evaluated by us for the year endedDecember 31, 2009, and identifies the respective portions thereof that we have evaluated on to the Company’smanagement/board of directors:

Independent QualifiedReserves Evaluator or Auditor

Description andPreparation Date of

EvaluationReport

Location of Reserves(Country or ForeignGeographic Area)

Net Present Value of Future Net Revenue(before income taxes, 10% discount rate)

Audited Evaluated Reviewed Total

M$ M$ M$ M$

AJM PetroleumConsultants

Exshaw Oil Corp.Reserve EstimationEconomic Evaluation,March 19, 2010

Canada — $224.1 — $224.1

5. In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined andare in accordance with the COGE Handbook. We express no opinion on the reserves data that we reviewed but didnot audit or evaluate.

6. We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurringafter their respective preparation dates.

7. Because the reserves data are based on judgements regarding future events, actual results will vary and thevariations may be material. However, any variation should be consistent with the fact that reserves are categorizedaccording to the probability of their recovery.

Executed as to our report referred to above.

AJM Petroleum ConsultantsFifth Avenue Place, East Tower6th Floor425 – 1st Street SWCalgary, AlbertaT2P 3P8

Original signed by: “Lynn Kis”

Lynn Kis, P. Eng.Vice President EngineeringExecution date: March 19, 2010

E-1

APPENDIX “F”

FORM 51-101F3REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE –

EXSHAW RESERVES

Management of Exshaw Oil Corp. (the “Company”) are responsible for the preparation and disclosure ofinformation with respect to the Company’s oil and gas activities in accordance with securities regulatory requirements.This information includes reserves data which are estimates of proved reserves and probable reserves and related futurenet revenue as at December 31, 2009, estimated using forecast prices and costs.

An independent qualified reserves evaluator has evaluated the Company’s reserves data. The report of theindependent qualified reserves evaluator is presented below.

The Reserves Committee of the board of directors of the Company has

(a) reviewed the Company’s procedures for providing information to the independent qualified reservesevaluator;

(b) met with the independent qualified reserves evaluator to determine whether any restrictions affected theability of the independent qualified reserves evaluator to report without reservation; and

(c) reviewed the reserves data with management and the independent qualified reserves evaluator.

The Reserves Committee of the board of directors has reviewed the Company’s procedures for assembling andreporting other information associated with oil and gas activities and has reviewed that information with management.The board of directors has approved

(a) the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data andother oil and gas information;

(b) the filing of Form 51-102F2 which is the report of the independent qualified reserves evaluator on thereserves data; and

(c) the content and filing of this report.

Because the reserves data are based on judgments regarding future events, actual results will vary and thevariations may be material. However, any variations should be consistent with the fact that the reserves are categorizedaccording to the probability of their recovery.

DATED as of this 13th day of October, 2010.

(signed) “Michael L. Rose” (signed) “Brian G. Robinson”

Michael L. Rose Brian G. RobinsonPresident, Chief Executive Officer and Director Vice President, Finance and Chief Financial Officer

(signed) “Robert W. Blakely” (signed) “Phillip A. Lamoreaux”

Robert W. Blakely Phillip A. LamoreauxDirector Director

F-1

CERTIFICATE OF THE COMPANY

Dated: November 15, 2010

This prospectus constitutes full, true and plain disclosure of all material facts relating to the securities offered bythis prospectus as required by the securities legislation of each of the provinces of Canada.

(signed) “Michael L. Rose”President and Chief Executive Officer

(signed) “Brian G. Robinson”Vice President, Finance and Chief Financial Officer

On behalf of the Board of Directors:

(signed) “Robert W. Blakely”Director

(signed) “Phillip A. Lamoreaux”Director

CC-1

CERTIFICATE OF THE UNDERWRITERS

Dated: November 15, 2010

To the best of our knowledge, information and belief, this prospectus constitutes full, true and plain disclosure ofall material facts relating to the securities offered by this prospectus as required by the securities legislation of each ofthe provinces of Canada.

Peters & Co. Limited(signed) “Christopher S. Potter”

FirstEnergy Capital Corp.(signed) “Nicholas J. Johnson”

Scotia Capital Inc.(signed) “Mike Jackson”

TD Securities Inc.(signed) “Alec W. G. Clark”

Cormark Securities Inc.(signed) “Ryan A. Shay”

CU-1

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