GHS Energy Conference Corporate Presentation June 2012

GHS Energy Conference Corporate Presentation

June 2012

Underground Energy Corp. Unlocking Shale Oil Opportunities in California & Nevada

TSX-V:UGE

OTCQX:UGGYF

Capital Structure Snapshot

2

UGE Listed on the TSX Venture Exchange

204.9 million Basic Shares Issued and Outstanding

339.4 million Fully Diluted Shares Outstanding

16.7% Insider Ownership

24.1% Institutional Ownership

59.2% Retail Ownership

$0.17 June 20, 2012 Closing Share Price

$34.8 million Market Capitalization (on Basic Shares)

$11.2 million Cash Balance at March 31, 2012

$25.6 million Working Capital at March 31, 2012

$23.6 million Enterprise Value (on Basic Shares)

$39.2 million Potential Proceeds from Dilutive Securities

59 million warrants at 21.7 cents – expires 09/13

52 million warrants at 40.5 - 43.4 cents – expires 08/13

California Focused Operations

San Francisco

Los Angeles

Las Vegas

CALIFORNIA

NEVADA

Underground leases

3

Zaca

Discovery of new Monterey play type in

Santa Maria Basin

• Basin has produced over 2 billion bbls oil

Impressive oil shows in initial wells at Zaca

Extension Project – production testing

underway

Substantial build out potential at Zaca

• Over 120 well locations identified based on

seismic / well control

Outstanding economics – Monterey has best

shale oil net backs in North America

Inventory of permitted well sites continues to

grow, > 40 permitted wells in California

Critical Mass achieved at Zaca and across

core prospect areas – 73,617 net acres

Note: Refer to the Appendix for detailed description of the Company's management team and board of directors 4

Complete California Based Team

Experienced, California-based technical and operations team assembled

• In excess of 200 years combined experience in California, proven ability to grow reserves and production in California

• Track record of building successful E&P companies – Management and Directors include founders of OSUM Oil Sands

Management Team

Michael Kobler – Founder, Chairman, President and CEO

Bruce Berwager – Chief Operating Officer

Peter Ballachey – Founder, CFO and Corporate Secretary

Simon Clarke – VP Corporate Development

Dana Brock – VP Engineering

David Hoyt – VP Exploration and Development

Randy Ray – Chief Geophysicist

Peter Bacon – Manager of Land

Board of Directors

Michael Kobler – Chairman

Randy Aldridge – Koch Oil Co., True Energy

Harland Johnson – ExxonMobil

Andrew Squires – OSUM Oil Sands, PetroCanada, Amoco

Douglas Urch – Bankers Petroleum, Rally Energy

5

History of Value Creation

Company

Inception

2007

Initial

Monterey

Lease

2008

Focus on

permitting

process

Added

California

expertise

2009

Permit for initial

26 wells

granted

Rounded out

senior

management

team

2010

Built land position

to ~80,000 net

acres in

California and

Nevada

IPO and raised

$25.5 million

2011

Discovered New Play

in Santa Maria Basin

Impressive oil

shows in initial wells

at Zaca

Target exit Production

450+ bbls/day

2012

6 Source of slide stats: California DOGGR (2001), US Department of Interior Bureau of Land Management

2nd largest onshore US oil producing state

• 5 of 10 largest fields in US

2010 production 740,000 boe/d

• 100% consumed in State

36 Billion BOE produced to date

Fully-integrated heavy oil infrastructure

Very robust oil price environment

54,000 producing wells in 2011

California’s refinery oil sources in 2011:

California’s Petroleum Basins

Oil and Gas Fields in California

San Joaquin Basin

Ventura & Santa Barbara

Channel

Los Angeles Basin

Santa Maria Basin

Los Angeles

Santa Barbara

San Francisco

Bakersfield

Sacramento Basin Total oil refining capacity in State is 2 million bopd

Pacific Ocean

Zaca

37%

13% 15%

11%

8%

16% California

Alaska

Saudi Arabia

Ecuador

Iraq

Other

7

Monterey Shale Formation

World Class Source Rock

Over 290 billion barrels of oil generated1

World Class Reservoir Rock

Produced over 2.5 billion barrels1

High organic content of 4-5%

Extremely thick shale packages of 500-3,500 ft

Compared to other US shale plays:

Bakken: 20-150 ft,

Eagle Ford: 75-300 ft,

Niobrara: >150 ft

Monterey players include:

San Joaquin Basin

Ventura & Santa Barbara Channel

Los Angeles Basin

Santa Maria Basin

Los Angeles

Underground Monterey prospects

1. Source: California DOGGR and USGS

Significant Monterey Shale Basins

$102.96

$20.00

$30.00

$40.00

$50.00

$60.00

$70.00

$80.00

$90.00

$100.00

$110.00

$120.00

May-09 May-10 May-11 May-12

WTI West Texas Intermediate- 39.6 API

MWSS Midway Sunset- 13.0 API

WCS Western Canada Select- 20.6 API

California: Premier Oil Price in North America

California (CA)

CA imports 62% of crude oil (~ 1 MM bopd) by sea (Alaska, Saudi Arabia, Ecuador, Iraq, Columbia, Brazil, Angola, Russia, Oman, Venezuela, Argentina, Peru, & Australia)

CA is not connected to other US oil supply or markets

CA oil prices currently more reflective of world prices (e.g. Brent) than WTI

Rig availability with low servicing costs and year–round access to CA projects

MWSS begins

trading at a

premium to WTI

8

US Oil Play Comparison

9 1. Sources: US EIA Review of Emerging Resources: US Shale Gas and Shale Oil Plays dated July 2011, Devon’s Analyst Day Presentation

dated April 4, 2012, and actual costs of Underground Energy, Inc.

Monterey Shale is largest shale oil formation in the US Estimated 15.4 billion bbls of recoverable oil

2/3 of total US shale oil potential

Play

Technically Recoverable

(BBO)1

Well Cost ($US MM)

EUR/well (MBbl)

IP Rate (BOPD)

Well Cost/EUR ($/BO)

IRR (%) @$85 WTI

California Monterey (SMV) 15.4 $2.0-2.5 375-550 200-300 $4.50-5.50 120%

Louisiana Tuscaloosa N/A $12.0-14.0 400-600 700-900 $23-30 N/A

Colorado Niobrara N/A $4.7-5.2 200-300 250-300 $17-24 N/A

Ohio Utica N/A $3.0-5.0 200-300 200-250 $15-17 80%

Texas Wolfberry N/A $1.8-2.0 120-170 100-125 $12-15 45%

Texas Avalon/Bone Springs 1.6 $5.5-6.0 330-550 500-550 $11-16 82%

N. Dakota/Montana Bakken 3.6 $7.0-9.0 500-600 500-900 $10-14 90%

Texas Eagle Ford Oil 3.4 $4.0-6.5 250-350 500-600 $8-11 90%

Oklahoma Mississippian Lime N/A $3.0-3.5 300-400 275-325 $8.50-10 100%

Santa Maria Basin / Greater Zaca Area

10

Santa Barbara

County

Pacific

Ocean

Conoco Phillips Santa Maria Refinery

Greka/Santa Maria Asphalt Refinery

PXP/Lompoc Oil & Gas Plant

All American Pipeline

Monterey Oil Field

Pipeline

Oil and Gas separation, Treatment and Gas Processing Plant

Refinery

Foxen Canyon Trend

To San Francisco

To Los Angeles

Santa Barbara County

2010 oil production of 25 million bbls

69,000 bopd in 2010 (onshore 9,400/ offshore 59,600)

935 producing wells

Approximately 2 billion bbls oil produced to date1

Cat

Canyon

251

Santa Maria

207

Gato Ridge

54

Orcutt

209

Lompoc 52

Barham

Ranch

All American Pipeline

Los Alamos

3 miles Estimated Ultimate Oil Recoveries (MMBO)

Underground Leases

To Los Angeles

1. Source: California DOGGR, BOEMRE and GLJ Petroleum Consultants

Asphaltea

101

Zaca

35 Santa Rita

Zaca Field Development Project

As Acquired by UGE

11

61 wells drilled to date at Zaca

Recovery to date of 32 MMbbls • 6.8% of OOIP

• Primary recovery only

UGE acquired 6,200 net acres at

Zaca Field Extension for lower risk

step out wells

Initial Management Estimates1: • 6 MMbbls 2P Reserves

• 20.8 MMbbls Prospective

Resources

GLJ Reserve Estimates2: • 1.8 MMbbls 2P / 3.6 MMbbls 3P

• 2P NPV10 BT – approx. $35.4 M

Increased Recovery potential from • Enhanced seismic

• Deviated/horizontal drilling

• EOR schemes • Thermal testing (1964-1967)

• Waterflooding (1953-1954

1. Management estimates which also include review by an internal qualified reservoir engineer

2. GLJ reserve estimates as at 31 December, 2011 from report dated 10 April, 2012

Existing Oil Well

Underground Energy Lease Boundary

Zaca Oil Field Recognized Boundary

Existing Zaca Field

Existing Seismic Line circa 1986

Zaca Field Extension Project

Achievements to Date

12

New Fault Block discovered

Upper and lower productive zones

identified by seismic and drilling

Initial wells have encountered

significant quality oil shows • Chamberlin 3-2 had a total of

1,700 feet of quality oil shows in

two Monterey sections

Land base increased to 12,183 net

acres and 96.7% WI Acquired minority interests in play

Added additional leases

13 drilling locations permitted

1,901 acres

774 acres

627 acres 218 acres

46 acres

159 acres

218 acres

2,121 acres

acquired May

2012

935 acres

acquired May

2012

1,213 acres

acquired May

2012 385 acres

acquired May

2012

3,943 Total Acres

Seismically

Defined

Existing Oil Well

Underground Energy Original Lease Boundary


Existing Zaca Field

Probable Geologic Structure Identified by Seismic


New UGE Seismic Lines

Permitted Pad Locations

Possible Geologic Structure Identified by Seismic

UGE Well Already Drilled

Underground Energy Acreage Additions

Permitted Well Location feet

0

3213

0

3213

feet

1,901 acres

774 acres

627 acres 218 acres

46 acres

159 acres

218 acres

3,943 Total Acres

Seismically

Defined


Existing Oil Well

Underground Energy Lease Boundary


Existing Zaca Field


New UGE Seismic Lines Permitted Pad Locations

Possible Geologic Structure Identified by Seismic

Potential Well Site

Being Permitted Pad Locations

UGE Well Already Drilled

Permitted/Being Permitted Well Location

Zaca Field Extension Project

Go-Forward Strategy

13

4 wells planned to be drilled by

year-end on current budget

Targeting 450+ bopd by year-end

Re-process / shoot new seismic on

West Side of lease / new lands

Continue to permit within field and

extend field boundary (~ 1 year) • 2 new well pads / 10 additional

wells in process

Full Development of East Side: • 60+ wells within existing field

• 60+ wells outside existing field

• Currently identified structures only

West side / new lands offer

significant additional potential


Zaca Field Seismically Defined Structures

UGE Chamberlin 3-2 Well

Original Zaca Field Block

South East Structure

North East Structure

North Structure

S-11 Structure

S-10 Structure

Oil Shows

Lower Thrust

Upper Thrust

UGE Chamberlin 3-2 Well

Original Zaca Field Block

Hathaway 1 Well

14

Current UGE Well Locations

Proposed UGE Wells

UGE Leaseholds

State of CA Oil Field Boundary

Previous Productive Wells

Zaca Field Magnetics and Anomalies

Residual Magnetics

UGE Chamberlin 1-2 & 2-2

UGE Chamberlin 3-2, 4-2 & 5-2

15

Zaca Idealized Cross Sections and Well

Penetrations

Basement

Sub-Thrust Block

Hathaway 1

Potreros 14

Carranza 22

Carranza 21

Chamberlin 5-2, 3-2, 4-2

1.5 Mile

16

Zaca / Monterey Shale Type Curves

17 1. Source: Occidental Petroleum Corporation, Minerals Management Service, DOGGR

Zaca Economics & Development Program

18

Typical Well All Wells

Type Curve

Infill Wells

Type Curve

Well Depth (MD feet) 5,500-8,500 4,000-5,500

Dry Hole Well Costs ($M) $1,500-$2,200 $1,200-$1,800

Completion Cost ($M) $300-$550 $200-$400

Total Well Cost ($M) $2,400 $1,900

UGE Interest (WI / NRI) 96.7% / 75.6% 96.7% / 75.6%

1st Month IP Rate (BOPD) 205 70

Cum. Production (MBO) 537 375

NPV @10% BT ($M)1 $ 11,023 $ 4,296

IRR (%) 110% 51%

Payback (years) 0.8 1.8

1. Economics are internal estimates using NYMEX Futures Strip Prices as of May 31, 2012 with adjustment for location and gravity

Zaca Resource

Upside Potential

Initial Build

Out Profile

Extended Build

Out Profile

Locations 60 120

UGE WI% 96.7% 96.7%

D,C&T Costs Per Well

($MM)

$2.2 $2.2

Base Case IP Rate

(bbls/d)

160 160

Reserves per Well

(Mbbls)

503.7 503.7

NPV per Well @10% BT

($MM) 1

$12.2 $12.2

UGE WI Program NPV

@10% BT ($MM)1

$708.0 $708.0

Added Value ($MM) $708 $1,416

0%

20%

40%

60%

80%

100%

120%

$-

$2,000

$4,000

$6,000

$8,000

$10,000

$12,000

$90.00 $80.00 $70.00 $60.00 $50.00 $45.00 $40.00

WTI Oil Price at Cushing, OK

Internal Rate of Return (%)

Net Present Value (BT) at 10% DCR ($M)

Zaca Sensitivity to Various Oil Prices

19

Other California Assets – Santa Maria

20

San Francisco

Modesto

Fresno

Santa Barbara

San Joaquin Basin

Santa Maria Basin

Stanislaus

County

Merced

County

Madera

County

Fresno

County

Tulare

County Kings

County

San Luis Obispo

County

San Benito

County

Producing Oil Field

Producing Gas Field

Underground Property

0 10 10 20 30 40 50 miles

Kern

County

Asphaltea Zaca Santa Barbara

County

Petroleum Basin

Bakersfield

Asphaltea

High impact exploration project

5,850 acres (100% WI – operated) in Santa

Barbara County, California

Analog fields: Zaca (32 MMboe), Cat Canyon (251

Mmboe), Orcutt (209 Mmboe)

Work at Zaca transferable to Asphaltea

2 potential structures identified – naturally

fractured

26 permitted wells

30+ miles of 2D swath seismic acquired 2011

currently being processed

2 billion bbls OOIP / 109 MMbbls Prospective

Resources1

Santa Rita

Santa Barbara County, California

80% WI (Operator), 1,217 gross acres (974 net

acres)

Monterey Shale & Point Sal sand oil targets

On trend with Lompoc Field (52 MMbbls)

Highlighted Property

Santa Rita

Pacific

Ocean

1. Source: GLJ Petroleum Consultants, effective date June 1, 2011

Other California Assets – San Joaquin

21

San Francisco

Modesto

Fresno

Santa Barbara

San Joaquin Basin

Santa Maria Basin

Stanislaus

County

Merced

County

Madera

County

Fresno

County

Tulare

County Kings

County

San Luis Obispo

County

San Benito

County

Producing Oil Field

Producing Gas Field

Underground Property

0 10 10 20 30 40 50 miles

Kern

County

Asphaltea

Zaca

Burrel

Santa Barbara

County

Petroleum Basin

Bakersfield

Highlighted Property

Devil’s Den Buttonwillow

Challenger

Pacific

Ocean

Santa Rita

Devil’s Den

Kern County, California

98.2% WI (Operator), 5,341 gross acres (5,246 net acres)

Shallow Monterey (Diatomite) and Tumey shale oil targets

Existing 3D sesimic

Analog fields: McKittrick (350 MMboe), Cymric (543 MMboe)

Burrel

Fresno County, California

88.2% WI, 8,973 gross acres (7,911 net acres)

Zilch & Vaqueros sand, Monterey & Kreyenhagen oil targets

1 producing well (35 bopd)

Existing 2D seismic

265,000 bbls 2P Reserves / 561,000 bbls 3P Reserves1

Analog fields: Helm (46 MMboe), Raisin City (47 Mmboe)

Buttonwillow

Kern County, California


Monterey/McClure shale, 44X and Randolph sand oil targets

In middle of Oxy/Venoco 3D seismic survey

Offset well planned by Venoco

Analog fields: North Shafter (10 MMboe), Rose (4.8 MMboe)

Challenger

Madera and Merced Counties, California


32 miles existing 3D seismic

Zilch, Blewett, Vaqueros/Temblor sands; and Kreyenhagen

& Moreno shale gas targets

1. Source: GLJ Petroleum Consultants, effective date December 31, 2011 21

Nevada Assets

“Early mover” advantage by building a strong

land position ahead of the curve

Complex geology, but existing conventional

discoveries have had very high production rates

Emerging shale oil potential (Bakken-like)

UGE has 31,286 net acres in 6 prospective

areas – history of production / oil shows

Noble Energy recently acquired Elko county

acreage for $50 per acre & began 3D seismic

Key competitors will help prove up plays -

Cabot (COG), EOG (EOG), SM Energy (SM),

Callon (CPE), PetroHunt

22

Underground leases

Blackburn

West

Flat Top

Trap

Springs Coaldale

Bull Run Deadman

Creek

RAILROAD VALLEY

46.2MMBO

Reno

Las

Vegas

Winnemucca Elko

Initial Exploration and Development Plan

23

Activity 1Q12 2Q12 3Q12 4Q12 Net Cost ($MM)

Acquire & Process Seismic (30 mi 2D)

$0.2

Drill 4 Monterey Shale Wells $10.0

Design & Build Facilities and additional

optimization work

$2.0

Permit Additional Drill Sites & Increase

Acreage

$0.2

Acquire & Process Seismic at Devil’s

Den (50 mi 2D) & Prepare to Drill

$0.2

Acquire Seismic at Buttonwillow (16 mi

3D, 30 mi 2D) & Prepare to Drill

$0.2

Continue Leasing at MVA. Reprocess

3D Seismic & Prepare to Drill

$0.2

Zaca

Drilling Seismic Other

$13.0

Other

CA

activity

0

452

$3,330,861

$0

$500,000

$1,000,000

$1,500,000

$2,000,000

$2,500,000

$3,000,000

$3,500,000

0

100

200

300

400

500

600

May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12

Cu

mu

lati

ve O

pe

rati

ng

Cas

h F

low

($

USM

M)

Dai

ly G

ross

Pro

du

ctio

n (

bo

pd

)

Month

Zaca Project Initial Development Profile 2012

Bopd Cumulative Operating Cash Flow

24

Initial Development Profile

1. Economics are based on management estimates of production post-royalty and based on May 31, 2012 NYMEX Futures strip prices

Key Assumptions

4 producing wells in 2012 (current budget only)

IP per well = 153 bopd

Primary recovery only

Exit production 452 bopd / annualized net

cash flow of $7.04 million

Contact Information

Underground Energy Corp.

3rd Floor

7 W. Figueroa Street

Santa Barbara, CA,

93101-5109

Tel: 805-845-4700

Fax: 805-845-1177

www.ugenergy.com

President & CEO – Mike Kobler

[email protected]

Phone: (805) 845-4700, x18

CFO – Peter Ballachey

[email protected]

Phone: (805) 845-4700, x17

COO – Bruce Berwager

[email protected]

Phone: (805) 845-4700, x11

VP Corp Development – Simon Clarke

[email protected]

Phone: (604) 551-9665

25

Cautionary and Forward Looking Statements Advisory

Underground Energy Corp. (Underground Energy) is a British Virgin Island holding company that owns Underground Energy, Inc., a Delaware corporation which is

an exploration and production company focused on unlocking oil from shale plays, principally in the Western US. Underground Energy is traded on the TSX

Venture Exchange under the trading symbol "UGE.“

Statements in this presentation contain forward-looking information and forward-looking statements within the meaning of applicable securities laws (collectively,

"forward-looking information"). Forward-looking information is frequently characterized by words such as "plan", "expect", "project", "intend", "believe", "anticipate",

"estimate" and other similar words, or statements that certain events or conditions "may" or "will" occur. In particular, forward-looking information in this

presentation includes, without limitation, statements with respect to: (i) the closing and closing date of the Company's proposed acquisition of oil and gas leases in

California; (ii) the Company's planned seismic operations to be conducted on such oil and gas leases; and (iii) the prospectivity of such oil and gas leases for oil

and gas and the anticipated drilling, completion and production results therefrom. Readers are cautioned that assumptions used in the preparation of forward-

looking information may prove to be incorrect.

Although we believe that the expectations and assumptions reflected in the forward-looking information are reasonable, there can be no assurance that such

expectations or assumptions will prove to be correct. In particular, assumptions have been made that: (i) Underground will be able to obtain equipment and

regulatory approvals in a timely manner to carry out exploration and development activities; (ii) Underground will have sufficient financial resources with which to

conduct its planned capital expenditures; and (iii) the current tax and regulatory regime will remain substantially unchanged. Certain or all of the forgoing

assumptions may prove to be untrue.

Forward-looking information is based on the opinions and estimates of management at the date the statements are made, and is subject to a variety of risks and

uncertainties and other factors (many of which are beyond the control of Underground) that could cause actual events or results to differ materially from those

anticipated in the forward-looking information. Some of the risks and other factors could cause results to differ materially from those expressed in the forward-

looking information include, but are not limited to: operational risks in exploration, development and production; delays or changes in plans; competition for and/or

inability to retain drilling rigs and other services; competition for, among other things, capital, acquisitions of reserves, undeveloped lands, skilled personnel and

supplies; risks associated to the uncertainty of reserve and resource estimates; governmental regulation of the oil and gas industry, including environmental

regulation; geological, technical, drilling and processing problems and other difficulties in producing reserves; the uncertainty of estimates and projections of

production, costs and expenses; unanticipated operating events or performance which can reduce production or cause production to be shut in or delayed;

incorrect assessments of the value of acquisitions; the need to obtain required approvals from regulatory authorities; stock market volatility; volatility in market

prices for oil and natural gas; liabilities inherent in oil and natural gas operations; access to capital; and other factors. Readers are cautioned that this list of risk

factors should not be construed as exhaustive.

The forward-looking information contained in this presentation is expressly qualified by this cautionary statement. Underground does not undertake any obligation

to update or revise any forward-looking statements to conform such information to actual results or to changes in our expectations except as otherwise required by

applicable securities legislation. Readers are cautioned not to place undue reliance on forward-looking information.

BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 bbl has been used and is based on an energy equivalency conversion

method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

26

Notes to Disclosure

1. Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from

undiscovered accumulations by application of future development projects. Prospective resources have both an associated

chance of discovery and a chance of development. There is no certainty that any portion of the prospective resources will be

discovered and, if discovered, there is no certainty that it will be commercially viable to produce any portion of those

resources. Prospective resources are undiscovered resources that indicate exploration opportunities and development

potential in the event a commercial discovery is made and should not be construed as reserves or contingent (discovered)

resources. Prospective resources in this presentation are reported on an unrisked, company interest basis.

2. The reserve and resource estimates in respect of the prospective resources for the Zaca Field for Underground were

prepared on October 27, 2011 with an effective date of November 1, 2011 and prepared in accordance with COGE

Handbook and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101") by a member of

management of Underground who is a "qualified reserves evaluator" as defined under NI 51-101.

3. The "best estimate" is considered to be the best estimate of the quantity that will actually be recovered. In terms of

prospective resources, it is equally likely that the actual quantities recovered will be greater or less than the best estimate. In

terms of discovered reserves, the “best estimate” is the combination of the proved plus probable reserves. If probabilistic

methods are used, there should be at least a 50 percent probability that the quantity actually recovered will equal or exceed

the best estimate.

4. The significant positive factors that are relevant to the management's estimate of the reserves and prospective resources

include production in close proximity to the assets and oil and gas shows in wells drilled in close proximity to the assets. A

significant negative factor that is relevant to management's estimate of prospective resources is that seismic attribute

mapping in the areas can be indicative but not certain in identifying resources.

5. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a

10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible

reserves.

6. The estimates of reserves and resources for individual properties may not reflect the same confidence level as estimates of

reserves and resources for all properties, due to the effects of aggregation.

7. Historical production data for both Zaca and Lompoc is based upon a report titled "California Monterey Reservoir Study

Project", prepared by Spivak, Mannon, Brigham, Surdam, Coombs, and Sageev and dated September 11, 1985 and the

records of the California Division of Oil and Gas and Geothermal Resources obtained by the Company on August 24, 2011.

27

Appendix

Management Team

Mike Kobler, Chairman, CEO and President 35 years international project management and engineering experience Founder of successful OSUM Oil Sands Corp., Calgary Founder and President, UCM Civil Engineering Consulting Firm focused on large infrastructure construction projects in California

Bruce Berwager, COO - Masters Petroleum Eng, P.Eng

32 years international oil and gas exploration, development, operations management and engineering roles with Chevron, Unocal, Conoco, Venoco and others

20+ years experience with Shale in California (Monterey), Texas (Barnett & Wolfcamp), Pennsylvania (Marcellus) Former Director and COO of Venoco, SVP and GM for California Ops-Warren Resources

Peter Ballachey, CFO and Corporate Secretary - CA, MS 35 years experience including 16 years senior financial CFO roles in Canada and USA Former CFO of OSUM Oil Sands Corp., Calgary

Simon Clarke, VP Corporate Development and Director, LLB Over 20 years capital markets experience Founder, Board Observer and Advisor to OSUM Oil Sands Corp Managing Director Invico Energy II Fund, Director of Argus Metals Corp., Director of Underground Energy, Inc.

David Hoyt, VP Exploration & Development – CPG, RPG Over 35 years exploration and development geology and geophysics project management and interpretation experience with ARCO,

TXO, Warren, Foothill and as an independent consultant Extensive academic and Industry experience in California, Nevada, Alaska

Randy Ray, Chief Geophysicist – BS, MS 36 years experience in Western US and an expert in integrated seismic and geological interpretation Professional Geologist, Texas and Wyoming

29

Independent Directors

Randy Aldridge – Independent Director 35 years international oil experience: Chairman- Koch Pipelines, President- Koch Petroleum Canada, President-Koch Oil Co.,

Chairman-True Energy Corp.

Board Member, Energy Holdings international Inc. and Husky/BP Toledo Refinery LLC

Harland Johnson – Independent Director 45 years technical and management experience in the upstream petroleum industry for Exxon Corporation and its affiliates

Formerly Presidente, Divisão de Exploração e Produção, Esso Brasileira de Petróleo Limitada; and President, Exxon Trinidad Limited

BSc (Honors) Chemistry, U of Alberta. PhD Metallurgy, U of Alberta

Andrew Squires – Independent Director 23 years experience in heavy oil and oil sands at Petro-Canada, Dome, Amoco, Paramount

Sr. Vice-President, OSUM Oil Sands Corp.

Douglas Urch – Independent Director Over 30 years oil & gas experience at RallyEnergy, Mohave Exploration, Sunshine Oilsands, Barrington Petroleum, TriGas Exploration

and Ryerson Oil & Gas

EVP, Finance and CFO Bankers Petroleum Ltd.

Director and Audit Committee Chairman at Petrodorado Energy

30

31

Other Players in the Santa Maria Basin

Key California Players

Largest Monterey Shale land holder in the State

(LA, Ventura and San Joaquin Basins)

10-15 exploratory wells per year planned

through 2015 to test shale prospects, $6.3 billion

CAPEX forecast over next four years

1.2 million acres in Monterey and 520 drilling

targets de-risked for oil-prone shale

development

Spent $1.6 billion on California in 2011 and is

operating 30 rigs– IPs of 300-400+

Now producing approx. 139,000 boepd from

Monterey and equivalent Shales

Ranked #1 in daily oil-equivalent production in California in 2011

2011 California operated production of 183,000 BOE/D, consisting of 165,000 bpd of crude oil

Primarily operates in the San Joaquin Basin Monterey Diatomite is the key producer / target

74 million barrels of oil produced by operations in the San Joaquin Valley in 2007, roughly 32% of the state’s annual oil production

Predominately steamflood operations in heavy oil reservoirs (Kern River, Midway-Sunset, Lost Hills, Cymric, Coalinga, San Ardo)

History of Monterey Shale

1895: 1st Monterey production in state at

Midway Sunset field t 1

1901: Union discovers Monterey Fractured

play at Orcutt Field, several more Monterey

fields developed in Santa Maria Basin from

1901 - 1942

t 2

1970’s-1990’s: Majors discover large Offshore

Monterey Fractured fields-Hondo, Pt. Arguello,

Pt. Pedernales, Sacate, Pescado, S. Ellwood

fields

t 3

1980’s:Shell/Chevron/Mobil develop

Monterey Diatomite with vertical frac’d wells

at Belridge and Lost Hills fields

t 4

1990’s: EOG develops diagenetic fractured

Monterey at Rose and N. Shafter fields t 5

1998: Oxy begins development of Monterey

matrix at Elk Hills field t 6

2005-11: Oxy explores and develops

Monterey equivalent formations in Ventura

and Los Angeles Basins 7

32

t 1

t 2

t 3

t 4

t 5

t 6

7

7

Monterey Play Types

Fracture Dominated • Outward basins – Structural traps – Hondo, Pt. Pedernales, Orcutt, Cat Canyon, Asphaltea – cleaner shales

• Inward basins – Diagenetic traps – Rose, North Shafter

Matrix Dominated: Mostly Diatomite – Belridge, Lost Hills, Elk Hills, Cymric, McKittrick

Dual Porosity: Matrix, micro-fractures and fractures – S. Ellwood, Midway-Sunset

33

Matrix Dominated Fracture Dominated 135 Miles

OFFSHORE-ONSHORE MONTEREY OUTBOUND BASINS ONSHORE SAN JOAQUIN INBOUND BASIN

Cat Canyon-Gato Ridge 147 MMBO

Pt. Pedernales 90 MMBO

Asphaltea

Closures 103 MMBO

Orcutt 209 MMBO

Cuyama 230 MMBO

Elk Hills 86 MMBO

North Shafter 17 MMBO

South Belridge 540 MMBO

Hondo 427 MMBO

Monterey Formation

UE’s Initial Monterey Prospects are Naturally Fractured, Conventional Structures

San Andreas Fault

Zaca Extension 21 MMBO

Key Attributes of Commercial Resource Plays TOC in excess of 1%

T-MAX of 450⁰F

Enhanced Permeability from Interbedded Sand/Carbonates or Natural Fractures

Play Formation Depth (ft)

Gross Thickness (ft)

Matrix Porosity (%)

Matrix Permeability (md)

Total Organic Content (%)

Bakken 7,000-11,000 20-150 3-12 0.005-0.2 2-18

Eagle Ford 8,0000-14,000 75-300 3-15 <0.0001-0.003 4.7

Niobrara 2,000-8,000 >150 4-8 na 5

Monterey (SMV) 3,500-10,000 500-3,500 5-30 0.0001-2 4-5

Monterey(SJV) 5,000-13,000 500-5,000 15-30 0.0001-2 0.1-4

Tumey 3,000-19,000 200-700 5-10 0.001 0.9-3.2

Kreyenhagen 3,000-19,000 400-2,400 5-10 <0.0001-1 4-12

Moreno (Gas) 4,000-14,000 100-11,000 na na 0.5-4

Chainman/Pilot > 8,200 400-2,400 5-10 Fracture Enhanced 1.5-11.7

Paleozoic >8,200-15,000 2,000-3,000 Fracture Enhanced Fracture Enhanced 4.4-25

US Shale Oil Comparison

34

High Profile US

Oil-Prone

Shale Plays

California

Resource Shale

Plays

Nevada

Emerging Shale

Plays

Local Prices

based on NYMEX Futures Strip

35 1. MWSS is an abbreviation for Midway Sunset, the benchmark for California heavy oil at 13˚ API

2. SMV is an abbreviation for Santa Maria Valley crude oil at 15˚ API

NYMEX Futures Strip Price as of May 31, 2012

Crude Oil Prices Natural Gas Prices

Year WTI @

Cushing Oklahoma

Current Differential MWSS (1)

vs WTI

Current Differential

SMV (2) vs MWSS

SMV Crude Oil Forecast

NYMEX Henry Hub

Local Gas Price

Differential

Local Gas Price

$US/bbl $US/bbl $US/bbl $US/bbl $US/mmbtu % of HH Nymex $US/mmbtu

2012 $94.14 $8.82 ($4.36) $98.60 $2.50 104% $2.60

2013 $84.90 $8.82 ($4.36) $89.36 $3.37 104% $3.50

2014 $84.60 $8.82 ($4.36) $89.06 $3.39 104% $3.53

2015 $84.66 $8.82 ($4.36) $89.12 $4.30 104% $4.47

2016 $84.86 $8.82 ($4.36) $89.32 $4.46 104% $4.64

2017 $85.19 $8.82 ($4.36) $89.65 $4.62 104% $4.80

2018 $85.64 $8.82 ($4.36) $90.10 $4.81 104% $5.00

2019 $86.02 $8.82 ($4.36) $90.48 $5.03 104% $5.23

2020 $86.44 $8.82 ($4.36) $90.90 $5.26 104% $5.47

2021+ $86.44 $8.82 ($4.36) $90.90 $5.26 104% $5.47

GHS Energy Conference Corporate Presentation June 2012

Business

Transcript of GHS Energy Conference Corporate Presentation June 2012