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APPENDIXD

ESTIMATES

of

RESERVES AND FUTURE REVENUE,CONTINGENT RESOURCES AND CASH FLOW,

AND PROSPECTIVE RESOURCES

to the

KRISENERGY LTD INTERESTin

CERTAIN OIL AND GAS PROPERTIES

located

OFFSHORE THAILAND, INDONESIA,CAMBODIA, AND VIETNAM AND

ONSHORE BANGLADESH

as of

DECEMBER 31, 2012

VOLUME 1 OF 2

BASED ON PRICE AND COST PARAMETERS

specified byKRISENERGY LTD

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July 1, 2013

Board of DirectorsKrisEnergy Ltd83 Clemenceau Avenue10-05, UE Square, Shell HouseSingapore 239920

Gentlemen:

In accordance with your request, we have estimated the proved, probable, and possible reserves andfuture revenue, as of December 31, 2012, to the KrisEnergy Ltd (KrisEnergy) interest in certain oil andgas properties located in Blocks B8/32 and B9A and Nong Yao Field, offshore Thailand; Kambuna

Field, offshore Indonesia; and Bangora Field, onshore Bangladesh. Also as requested, we haveestimated the development pending contingent resources and cash flow, as of December 31, 2012, tothe KrisEnergy interest in certain discoveries located offshore Thailand, Indonesia, and Cambodia; thedevelopment unclarified contingent resources, as of December 31, 2012, to the KrisEnergy workinginterest in certain other discoveries located offshore Thailand, Indonesia, and Cambodia and onshoreBangladesh; and the prospective resources, as of December 31, 2012, to the KrisEnergy workinginterest in prospects and leads located offshore Thailand, Indonesia, Cambodia, and Vietnam andonshore Bangladesh. It is our understanding that KrisEnergy executed a share sale purchaseagreement on April 8, 2013, to acquire a 30 percent working interest and operatorship in Block 9,onshore Bangladesh. The acquisition is contingent upon the approval of the Bangladesh Oil, Gas &Mineral Corporation (Petrobangla) and will have a retroactive effective date of January 1, 2013. Asrequested, the KrisEnergy interest shown in this report for the Bangladesh properties is the interest

expected to be owned when all approvals are finalized. It is also our understanding that KrisEnergysigned a farm-out agreement on March 15, 2013, to acquire a 30 percent working interest andoperatorship in Block G6/48, offshore Thailand. The transaction is pending approval by the Thailandgovernment and will have a retroactive effective date of January 1, 2013. As requested, the KrisEnergyinterest shown in this report for Block G6/48 is the interest expected to be owned when all approvalsare finalized. A list of KrisEnergys assets included in this report is shown on Table I. We completedour evaluation on or about the date of this letter. This report has been prepared using price and costparameters specified by KrisEnergy, as discussed in subsequent paragraphs of this letter. Monetaryvalues shown in this report are expressed in United States dollars ($), thousands of United Statesdollars (M$), or millions of United States dollars (MM$). It is our understanding that KrisEnergy intendsto use this report as part of its filing on the Singapore Stock Exchange (SGX).

The estimates in this report have been prepared in accordance with the definitions and guidelines setforth in the 2007 Petroleum Resources Management System (PRMS) approved by the Society ofPetroleum Engineers (SPE). As presented in the 2007 PRMS, petroleum accumulations can beclassified, in decreasing order of likelihood of commerciality, as reserves, contingent resources, orprospective resources. Different classifications of petroleum accumulations have varying degrees oftechnical and commercial risk that are difficult to quantify; thus reserves, contingent resources, andprospective resources should not be aggregated without extensive consideration of these factors.Definitions are presented immediately following this letter. The tables following the definitions set forthour estimates of reserves, contingent resources, and prospective resources, by category, to theKrisEnergy interest for each asset area. Following the tables is a list of abbreviations used in thisreport.

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RESERVES

Reserves are those quantities of petroleum anticipated to be commercially recoverable from knownaccumulations by application of development projects from a given date forward under defined

conditions. Reserves must be discovered, recoverable, commercial, and remaining as of the evaluationdate based on the planned development projects to be applied. Proved reserves are those quantities ofoil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonablecertainty to be commercially recoverable; probable and possible reserves are those additional reserveswhich are sequentially less certain to be recovered than proved reserves.

As presented in the accompanying summary projections, Tables II through IX, we estimate the gross(100 percent) reserves and working interest reserves and future net revenue to the KrisEnergy interestin these properties, as of December 31, 2012, to be:

Gross (100 Percent)Reserves

Working InterestReserves Future Net Revenue(1) (M$)

CategoryOil

(MBBL)Gas

(MMCF)Oil

(MBBL)Gas

(MMCF) TotalPresent Worth

At 10%

Proved Developed Producing 21,537.4 131,574.6 1,059.6 22,699.3 (867.0)(2) 11,454.2Proved Developed Non-Producing 44.4 15,444.9 13.3 4,633.5 6,468.5 5,482.2Proved Undeveloped 21,019.0 78,558.5 974.1 3,640.8 69,407.3 53,452.1

Proved (1P) 42,600.8 225,578.0 2,047.1 30,973.5 75,008.8 70,388.5

Probable 122,916.4 891,322.0 8,893.2 93,586.4 322,325.6 189,798.6

Proved + Probable (2P) 165,517.2 1,116,900.0 10,940.3 124,559.9 397,334.4 260,187.1

Possible 40,407.8 362,072.5 3,585.5 52,554.8 162,789.5 83,671.4

Proved + Probable + Possible (3P) 205,925.0 1,478,972.5 14,525.8 177,114.7 560,123.9 343,858.5

Totals may not add because of rounding.

(1) Future net revenue is after deductions for royalties and KrisEnergys share of future capital costs,abandonment costs, operating expenses, special remuneratory benefit, training fees, and income taxes.

(2) Future net revenue is negative after deducting estimated abandonment costs.

The oil volumes shown include crude oil and condensate. Oil volumes are expressed in thousands ofbarrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed inmillions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved, probable, and possible reserves. Reservescategorization conveys the relative degree of certainty; reserves subcategorization is based ondevelopment and production status. The estimates of reserves and future revenue included herein

have not been adjusted for risk.

Gross revenue for the reserves shown in this report is KrisEnergys share of the gross (100 percent)revenue from the properties after deductions for royalties. Future net revenue is after additionaldeductions for KrisEnergys share of future capital costs, abandonment costs, operating expenses,special remuneratory benefit, training fees, and income taxes. The future net revenue has beendiscounted at an annual rate of 10 percent to determine its present worth, which is shown to indicatethe effect of time on the value of money. Future net revenue presented in this report, whetherdiscounted or undiscounted, should not be construed as being the fair market value of the properties.

We have made no investigation of potential gas volume and value imbalances resulting fromoverdelivery or underdelivery to the KrisEnergy interest. Therefore, our estimates of reserves and

future revenue do not include adjustments for the settlement of any such imbalances; our projectionsare based on KrisEnergy receiving its net revenue interest share of estimated future gross gasproduction.

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CONTINGENT RESOURCES

Contingent resources are those quantities of petroleum which are estimated, as of a given date, to bepotentially recoverable from known accumulations, but for which the applied project or projects are not

yet considered mature enough for commercial development because of one or more contingencies.The discoveries assessed in this report have been subclassified as development pending ordevelopment unclarified. The 2007 PRMS defines a development pending discovery as a discoveredaccumulation where project activities are ongoing to justify commercial development in the foreseeablefuture and a development unclarified discovery as a discovered accumulation where project activitiesare on hold and/or where justification as a commercial development may be subject to significantdelay. The contingent resources shown in this report are contingent upon one or more of the following:(1) commitment of the license partners to develop the resources, (2) submission and approval of aPlan of Development (POD), Production Area Application (PAA), or Production Permit Application(PPA), (3) completion of a gas sales agreement, and (4) collection of additional technical data, to becollected through delineation wells and flow tests, to establish commercial viability. The costs requiredto resolve these contingencies have not been included in this report; estimates of cash flow are based

on the assumption that applicable contingencies will be successfully addressed. If these contingenciesare successfully addressed, some portion of the contingent resources estimated in this report may bereclassified as reserves; our estimates have not been risked to account for the possibility that thecontingencies are not successfully addressed. This report does not include economic analysis for thedevelopment unclarified contingent resources. Because of the early stage of development of theseprojects, we did not perform an economic analysis on these resources; as such, the economic status ofthese resources is undetermined.

We estimate the gross (100 percent) contingent resources and working interest contingent resourcesand net contingent cash flow to the KrisEnergy interest in these discoveries, as of December 31, 2012,to be:

Gross (100 Percent)Contingent Resources Working InterestContingent Resources Net Contingent Cash Flow(1) (M$)

Subclassification/CategoryOil

(MBBL)Gas

(MMCF)Oil

(MBBL)Gas

(MMCF) TotalDiscounted

At 10%

Development PendingLow Estimate (1C) 8,600.0 180,500.0 2,273.8 76,712.5 93,654.3 21,791.8Best Estimate (2C) 35,538.1 322,325.0 9,222.4 147,618.8 377,595.9 183,361.8High Estimate (3C) 64,599.5 449,385.3 17,031.4 208,868.0 659,986.8 331,058.3

Development Unclarified(2)

Low Estimate (1C) 1,669.4 11,002.4 407.2 3,054.6 (2) (2)

Best Estimate (2C) 3,656.7 153,032.4 898.1 59,533.9 (2) (2)

High Estimate (3C) 27,861.6 310,840.7 6,953.4 112,203.7 (2) (2)

Note: Contingent resources are the arithmetic sum of multiple probability distributions.

(1) Net contingent cash flow is after deductions for royalties and KrisEnergys share of future capital costs,abandonment costs, operating expenses, special remuneratory benefit, and income taxes.

(2) Because of the early stage of development of these projects, we did not perform an economic analysis onthese resources; as such, the economic status of these resources is undetermined.

The oil volumes shown include crude oil and condensate.

The contingent resources shown in this report have been estimated using probabilistic methods. Onceall contingencies have been successfully addressed, the probability that the quantities of contingentresources actually recovered will equal or exceed the estimated amounts is 90 percent for the lowestimate, 50 percent for the best estimate, and 10 percent for the high estimate. For the purposes of

this report, the volumes and parameters associated with the low, best, and high estimate scenarios ofcontingent resources are referred to as 1C, 2C, and 3C, respectively. The estimates of contingentresources included herein have not been adjusted for development risk. As recommended in the

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PRMS, the 1C, 2C, and 3C contingent resources have been aggregated beyond the project level byarithmetic summation; therefore, these totals do not include the portfolio effect that might result fromstatistical aggregation.

Gross contingent revenue shown in this report for the development pending discoveries is KrisEnergysshare of the gross (100 percent) revenue from the properties after deductions for royalties. Netcontingent cash flow is after additional deductions for KrisEnergys share of future capital costs,abandonment costs, operating expenses, special remuneratory benefit, and income taxes. The netcontingent cash flow has been discounted at an annual rate of 10 percent to indicate the effect of timeon the value of money; the contingent cash flow, whether discounted or undiscounted, should not beconstrued as being the fair market value of the properties.

PROSPECTIVE RESOURCES

Prospective resources are those quantities of petroleum which are estimated, as of a given date, to bepotentially recoverable from undiscovered accumulations by application of future development projects.The prospective resources included in this report should not be construed as reserves or contingentresources; they represent exploration opportunities and quantify the development potential in the eventa petroleum discovery is made. The undiscovered accumulations assessed in this report have beensubclassified as prospects and leads. The 2007 PRMS defines a prospect as a project associated witha potential accumulation that is sufficiently well defined to represent a viable drilling target, a lead as aproject associated with a potential accumulation that is currently poorly defined and requires more dataacquisition and/or evaluation in order to be classified as a prospect, and a play as a project associatedwith a prospective trend of potential prospects, but which requires more data acquisition and/orevaluation in order to define specific leads or prospects. A geologic risk assessment was performed forthese prospects and leads, as discussed in subsequent paragraphs. Because of the early stage ofdevelopment of these prospects and leads, we did not perform an economic analysis on theseresources; as such, the economic status of these resources is undetermined.

Totals of unrisked prospective resources beyond the prospect and lead levels are not reflective ofvolumes that can be expected to be recovered and are shown for convenience only. Because of thegeologic risk associated with each prospect and lead, meaningful totals beyond these levels can bedefined only by summing risked prospective resources. Such risk is often significant.

We estimate the unrisked and risked gross (100 percent) prospective resources and the unrisked andrisked working interest prospective resources to the KrisEnergy interest in these prospects and leads,as of December 31, 2012, to be:

Prospective Resources

Gross (100 Percent) Working Interest

Unrisked Risked Unrisked Risked

Subclassification/Category

Oil(MMBBL)

Gas(BCF)

Oil(MMBBL)

Gas(BCF)

Oil(MMBBL)

Gas(BCF)

Oil(MMBBL)

Gas(BCF)

ProspectsLow Estimate 948.3 3,125.7 140.1 460.4 237.3 819.6 35.0 125.7Best Estimate 1,601.5 5,488.3 244.7 724.1 400.9 1,437.3 61.2 200.0High Estimate 2,762.0 11,577.4 425.1 1,313.0 691.5 3,020.3 106.3 367.1

LeadsLow Estimate 1,529.5 2,498.4 172.3 355.7 409.2 1,138.4 46.9 168.2Best Estimate 2,255.9 3,577.3 244.9 513.5 595.2 1,492.8 65.7 221.7High Estimate 3,475.4 5,354.7 369.9 800.4 905.8 2,072.3 97.8 321.4

Note: Prospective resources are the arithmetic sum of multiple probability distributions.

The oil volumes shown include crude oil and condensate. Oil volumes are expressed in millions ofbarrels (MMBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed inbillions of cubic feet (BCF) at standard temperature and pressure bases.

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The prospective resources shown in this report have been estimated using probabilistic methods andare dependent on a petroleum discovery being made. If a discovery is made and development isundertaken, the probability that the recoverable volumes will equal or exceed the unrisked estimatedamounts is 90 percent for the low estimate, 50 percent for the best estimate, and 10 percent for the

high estimate. As recommended in the PRMS, the low, best, and high estimate prospective resourceshave been aggregated beyond the block and area levels by arithmetic summation; therefore, thesetotals do not include the portfolio effect that might result from statistical aggregation.

Unrisked prospective resources are estimated ranges of recoverable oil and gas volumes assumingtheir discovery and development and are based on estimated ranges of undiscovered in-placevolumes. The estimates for risked resources are derived directly from the estimates for unriskedresources, incorporating a geologic risk assessment for each prospect; such risked resources do notincorporate a development risk assessment. Geologic risking of prospective resources addresses theprobability of success for the discovery of a significant quantity of potentially moveable petroleum; thisrisk analysis is conducted independent of estimations of petroleum volumes. Principal geologic riskelements of the petroleum system include (1) trap and seal characteristics; (2) reservoir presence andquality; (3) source rock capacity, quality, and maturity; and (4) timing, migration, and preservation of

petroleum in relation to trap and seal formation. Risk assessment is a highly subjective processdependent upon the experience and judgment of the evaluators and is subject to revision with furtherdata acquisition or interpretation. Included in this report is a discussion of the primary geologic riskelements for each prospect and lead.

Each prospect and lead was evaluated to determine ranges of in-place and recoverable petroleum andwas risked as an independent entity without dependency between potential prospect drilling outcomes.If petroleum discoveries are made, smaller-volume prospects and leads may not be commercial toindependently develop, although they may become candidates for satellite developments and tie-backsto existing infrastructure at some future date. The development infrastructure and data obtained fromearly discoveries will alter both geologic risk and future economics of subsequent discoveries anddevelopments.

It should be understood that the prospective resources discussed and shown herein are thoseundiscovered, speculative resources estimated beyond reserves or contingent resources wheregeological and geophysical data suggest the potential for discovery of petroleum but where the level ofproof is insufficient for classification as reserves or contingent resources. The unrisked prospectiveresources shown in this report are the range of volumes that could reasonably be expected to berecovered in the event of the discovery and development of these prospects and leads.

ECONOMIC PARAMETERS

As requested, this report has been prepared using oil and gas price parameters specified byKrisEnergy. While only one economic case is presented, it is intended to represent KrisEnergysinterpretation of constant and forecast cases. Oil prices for the reserves and development pending

contingent resources are based on the December 31, 2012, EIA Europe Brent Spot Price FOB of$110.80 per barrel and are adjusted by field area for quality, transportation fees, and regional pricedifferentials. Oil prices are held constant throughout the lives of the properties. Gas prices for BlockB8/32 and Block B9A reserves are based on the Tantawan Gas Sales Agreement price of $6.112 perMMBTU and are adjusted by field area for energy content. The gas price for Bangora Field reserves isthe contract price of $2.315 per MCF. Gas prices for Block B8/32, Block B9A, and Bangora Fieldreserves are held constant throughout the lives of the properties. Gas prices for Kambuna Fieldreserves are based on contract prices and are adjusted by field area for energy content. KambunaField gas prices, before adjustments, are shown in the following table:

PeriodEnding

Gas Price($/MMBTU)

2-28-2013 5.2807-31-2013 5.340Thereafter 5.440

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Gas prices for the development pending contingent resources are based on recent gas contracts insimilar areas. The gas price used for Lengo and East Lengo Fields is $6.500 per MMBTU, which isthen adjusted for energy content. The gas price used for Kutai Field is $6.000 per MMBTU, which isthen adjusted for energy content. Gas prices for the development pending contingent resources are

escalated 3 percent per year from the year of first production throughout the lives of the properties.

Operating costs used in this report are based on operating expense records of and budgets preparedby the operators of the properties, as provided by KrisEnergy. These costs include the per-welloverhead expenses allowed under concession agreements along with estimates of costs to be incurredat and below the field level. Headquarters general and administrative overhead expenses ofKrisEnergy are included to the extent that they are covered under concession agreements for theoperated properties. As requested, operating costs are held constant throughout the lives of theproperties.

Capital costs used in this report were provided by KrisEnergy and are based on budgeted expendituresand actual costs from recent activity. Capital costs are included as required for workovers, newdevelopment wells, and production equipment. Based on our understanding of future developmentplans, a review of the records provided to us, and our knowledge of similar properties, we regard theseestimated capital costs to be reasonable. Abandonment costs used in this report are KrisEnergysestimates of the costs to abandon the wells, platforms, and production facilities, net of any salvagevalue. As requested, capital costs and abandonment costs are held constant to the date ofexpenditure.

GENERAL INFORMATION

As shown in the Table of Contents, this report includes an executive summary and, for each asset, atechnical discussion with pertinent maps, logs, and figures.

This report does not include any value that could be attributed to interests in undeveloped acreagebeyond those tracts for which undeveloped reserves and contingent resources have been estimated.For the purposes of this report, we did not perform any field inspection of the properties, nor did weexamine the mechanical operation or condition of the wells and facilities. Based on the informationprovided by KrisEnergy, it is our opinion that a field visit was not required and would not materiallyaffect our evaluation. We have not investigated possible environmental liability related to theproperties; therefore, our estimates do not include any costs due to such possible liability.

The reserves, contingent resources, and prospective resources shown in this report are estimates onlyand should not be construed as exact quantities. Estimates may increase or decrease as a result ofmarket conditions, future operations, changes in regulations, or actual reservoir performance. Ourestimates are based on certain assumptions including, but not limited to, that the properties will bedeveloped consistent with current development plans, that the properties will be operated in a prudent

manner, that no governmental regulations or controls will be put in place that would impact the ability ofthe interest owner to recover the volumes, and that our projections of future production will proveconsistent with actual performance. If these volumes are recovered, the revenues therefrom and thecosts related thereto could be more or less than the estimated amounts. Because of governmentalpolicies and uncertainties of supply and demand, the sales rates, prices received, and costs incurredmay vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, welllogs, geologic maps, seismic data, well test data, production data, historical price and cost information,and property ownership interests. The reserves, contingent resources, and prospective resources inthis report have been estimated using a combination of deterministic and probabilistic methods; theseestimates have been prepared in accordance with generally accepted petroleum engineering and

evaluation principles set forth in the Standards Pertaining to the Estimating and Auditing of Oil and GasReserves Information promulgated by the SPE (SPE Standards). We used standard engineering andgeoscience methods, or a combination of methods, including performance analysis, volumetric

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analysis, and analogy, that we considered to be appropriate and necessary to classify, categorize, andestimate volumes in accordance with the 2007 PRMS definitions and guidelines. The contingent andprospective resources and a portion of the reserves shown in this report are for undeveloped locations;such volumes are based on estimates of reservoir volumes and recovery efficiencies along with

analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gasevaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data;therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from KrisEnergy, various operators of the properties,public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) andwere accepted as accurate. Supporting work data are on file in our office. The contractual rights to theproperties have not been examined by NSAI, nor has the actual degree or type of interest owned beenindependently confirmed by us.

QUALIFICATIONS

The technical persons responsible for preparing the estimates presented herein meet the requirementsregarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standardsand the proposed introduction of the Mainboard Listing Rules for mineral, oil, and gas companiesissued on June 20, 2012. We are independent petroleum engineers, geologists, geophysicists, andpetrophysicists; we do not own an interest in these properties, we are not employed on a contingentbasis, and we are not officers or proposed officers of any group, holding, or associated company ofKrisEnergy. Furthermore, none of our staff or associates own shares or equity in KrisEnergy.

NSAI was established in 1961 and has offices located at 1601 Elm Street, Suite 4500, Dallas, 75201,and 1221 Lamar, Suite 1200, Houston, 77010. NSAI performs consulting petroleum engineeringservices under Texas Board of Professional Engineers Registration No. F-2699 and has conductedreserves certifications, technical studies, economic evaluations, and advisory work throughout the

world.

This report has been supervised by Mr. Scott Frost and Mr. Allen Evans. Mr. Frost and Mr. Evans donot have, nor do they expect to receive, any direct or indirect interest in the securities of KrisEnergy, itsparents, or its subsidiaries.

Mr. Frost is a Licensed Professional Engineer in the State of Texas (No. 88738), is a member in goodstanding of the SPE, and has over 30 years of practical experience in petroleum engineering, with over25 years of experience in the estimation and evaluation of reserves. He graduated from VanderbiltUniversity in 1979 with a Bachelor of Engineering Degree in Mechanical Engineering and from TulaneUniversity in 1984 with a Master of Business Administration Degree.

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Mr. Evans is a Licensed Professional Geoscientist in the State of Texas, (Geology, No. 1286), is amember in good standing of the American Association of Petroleum Geologists, and has over 30 yearsof practical experience in geological and geophysical studies and evaluations, with over 15 years ofexperience in the estimation and evaluation of reserves. He graduated from Old Dominion University in

1981 with a Bachelor of Science Degree in Geology and in 1987 with a Master of Science Degree inGeology.

For and behalf of

NETHERLAND, SEWELL & ASSOCIATES, INC.

Texas Registered Engineering Firm F-2699

By:C.H. (Scott) Rees III, P.E.Chairman and Chief Executive Officer

By: By:Philip S. (Scott) Frost, P.E. 88738 Allen E. Evans, Jr., P.G. 1286Senior Vice President Vice President

Date Signed: July 1, 2013 Date Signed: July 1, 2013

PSF:TDL

Please be advised that the digital document you are viewing is provided by Netherland, Sewell &Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to besubstantively the same as the original signed document maintained by NSAI. The digital document issubject to the parameters, limitations, and conditions stated in the original document. In the event ofany differences between the digital document and the original document, the original document shallcontrol and supersede the digital document.

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PETROLEUM RESERVES AND RESOURCES CLASSIFICATION AND DEFINITIONSExcerpted from the Petroleum Resources Management System Approved by

the Society of Petroleum Engineers (SPE) Board of Directors, March 2007

This document contains information excerpted from definitions and guidelines prepared by the Oil and GasReserves Committee of the Society of Petroleum Engineers (SPE) and reviewed and jointly sponsored by theWorld Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG), and the Society ofPetroleum Evaluation Engineers (SPEE).

Preamble

Petroleum resources are the estimated quantities of hydrocarbons naturally occurring on or within the Earths crust.Resource assessments estimate total quantities in known and yet-to-be-discovered accumulations; resourcesevaluations are focused on those quantities that can potentially be recovered and marketed by commercial projects. Apetroleum resources management system provides a consistent approach to estimating petroleum quantities,evaluating development projects, and presenting results within a comprehensive classification framework.

These definitions and guidelines are designed to provide a common reference for the international petroleumindustry, including national reporting and regulatory disclosure agencies, and to support petroleum project andportfolio management requirements. They are intended to improve clarity in global communications regardingpetroleum resources. It is expected that this document will be supplemented with industry education programs andapplication guides addressing their implementation in a wide spectrum of technical and/or commercial settings.

It is understood that these definitions and guidelines allow flexibility for users and agencies to tailor application fortheir particular needs; however, any modifications to the guidance contained herein should be clearly identified.The definitions and guidelines contained in this document must not be construed as modifying the interpretation orapplication of any existing regulatory reporting requirements.

1.0 Basic Principles and Definitions

The estimation of petroleum resource quantities involves the interpretation of volumes and values that have aninherent degree of uncertainty. These quantities are associated with development projects at various stages ofdesign and implementation. Use of a consistent classification system enhances comparisons between projects,

groups of projects, and total company portfolios according to forecast production profiles and recoveries. Such asystem must consider both technical and commercial factors that impact the projects economic feasibility, itsproductive life, and its related cash flows.

1.1 Petroleum Resources Classification Framework

Petroleum is defined as a naturally occurring mixtureconsisting of hydrocarbons in the gaseous, liquid, orsolid phase. Petroleum may also contain non-hydrocarbons, common examples of which arecarbon dioxide, nitrogen, hydrogen sulfide and sulfur.In rare cases, non-hydrocarbon content could begreater than 50%.

The term resources as used herein is intended toencompass all quantities of petroleum naturallyoccurring on or within the Earths crust, discoveredand undiscovered (recoverable and unrecoverable),plus those quantities already produced. Further, itincludes all types of petroleum whether currentlyconsidered conventional or unconventional.

Figure 1-1 is a graphical representation of the SPE/WPC/ AAPG/SPEE resources classification system.The system defines the major recoverable resourcesclasses: Production, Reserves, ContingentResources, and Prospective Resources, as well as

Unrecoverable petroleum.

PRODUCTION

UNRECOVERABLE

UNRECOVERABLE

Range of UncertaintyNottoscale

TOTALPETROLEUMINITIALLY-IN-PLACE

(PIIP)

COMMERCIAL

IncreasingChan

ceofCommerciality

SUB-CO

MMERCIAL

UNDISCOVERED

PIIP

DISCOVERED

PIIP

RESERVES

CONTINGENT

RESOURCES

PROSPECTIVE

RESOURCES

1P

1C

LowEstimate

Proved Probable Possible3P2P

3C2C

High

Estimate

BestEstimate

Figure 1-1: Resources Classification Framework.

Definitions - Page 1 of 12

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The Range of Uncertainty reflects a range of estimated quantities potentially recoverable from an accumulationby a project, while the vertical axis represents the Chance of Commerciality, that is, the chance that the projectthat will be developed and reach commercial producing status. The following definitions apply to the majorsubdivisions within the resources classification:

TOTAL PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated to existoriginally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as ofa given date, to be contained in known accumulations prior to production plus those estimated quantities inaccumulations yet to be discovered (equivalent to total resources).

DISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated, as of agiven date, to be contained in known accumulations prior to production.

PRODUCTION is the cumulative quantity of petroleum that has been recovered at a given date.While all recoverable resources are estimated and production is measured in terms of the salesproduct specifications, raw production (sales plus non-sales) quantities are also measured andrequired to support engineering analyses based on reservoir voidage (see ProductionMeasurement, section 3.2).

Multiple development projects may be applied to each known accumulation, and each project will recover anestimated portion of the initially-in-place quantities. The projects shall be subdivided into Commercial andSub-Commercial, with the estimated recoverable quantities being classified as Reserves and ContingentResources respectively, as defined below.

RESERVES are those quantities of petroleum anticipated to be commercially recoverable byapplication of development projects to known accumulations from a given date forward underdefined conditions. Reserves must further satisfy four criteria: they must be discovered,

recoverable, commercial, and remaining (as of the evaluation date) based on the developmentproject(s) applied. Reserves are further categorized in accordance with the level of certaintyassociated with the estimates and may be sub-classified based on project maturity and/orcharacterized by development and production status.

CONTINGENT RESOURCES are those quantities of petroleum estimated, as of a given date, tobe potentially recoverable from known accumulations, but the applied project(s) are not yetconsidered mature enough for commercial development due to one or more contingencies.Contingent Resources may include, for example, projects for which there are currently no viablemarkets, or where commercial recovery is dependent on technology under development, or whereevaluation of the accumulation is insufficient to clearly assess commerciality. ContingentResources are further categorized in accordance with the level of certainty associated with theestimates and may be subclassified based on project maturity and/or characterized by theireconomic status.

UNDISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum estimated, as of agiven date, to be contained within accumulations yet to be discovered.

PROSPECTIVE RESOURCES are those quantities of petroleum estimated, as of a given date, tobe potentially recoverable from undiscovered accumulations by application of future developmentprojects. Prospective Resources have both an associated chance of discovery and a chance ofdevelopment. Prospective Resources are further subdivided in accordance with the level ofcertainty associated with recoverable estimates assuming their discovery and development andmay be sub-classified based on project maturity.

UNRECOVERABLE is that portion of Discovered or Undiscovered Petroleum Initially-in-Place quantitieswhich is estimated, as of a given date, not to be recoverable by future development projects. A portion of

these quantities may become recoverable in the future as commercial circumstances change or


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technological developments occur; the remaining portion may never be recovered due to physical/chemicalconstraints represented by subsurface interaction of fluids and reservoir rocks.

Estimated Ultimate Recovery (EUR) is not a resources category, but a term that may be applied to anyaccumulation or group of accumulations (discovered or undiscovered) to define those quantities of petroleumestimated, as of a given date, to be potentially recoverable under defined technical and commercial conditions plusthose quantities already produced (total of recoverable resources).

1.2 Project-Based Resources Evaluations

The resources evaluation process consists of identifying a recovery project, or projects, associated with apetroleum accumulation(s), estimating the quantities of Petroleum Initially-in-Place, estimating that portion of thosein-place quantities that can be recovered by each project, and classifying the project(s) based on its maturitystatus or chance of commerciality.

This concept of a project-based classification system is further clarified by examining the primary data sourcescontributing to an evaluation of net recoverable resources (see Figure 1-2) that may be described as follows:

RESERVOIR(in-place volumes)

PROJECT(production/cash flow)

PROPERTY(ownership/contract terms)

Entitlement

Net

Recoverable

Resources

RESERVOIR(in-place volumes)

PROJECT(production/cash flow)

PROPERTY(ownership/contract terms)

Entitlement

Net

Recoverable

Resources

Figure 1-2: Resources Evaluation Data Sources.

The Reservoir (accumulation): Key attributes include the types and quantities of Petroleum Initially-in-Placeand the fluid and rock properties that affect petroleum recovery.

The Project: Each project applied to a specific reservoir development generates a unique production andcash flow schedule. The time integration of these schedules taken to the projects technical, economic, orcontractual limit defines the estimated recoverable resources and associated future net cash flow projectionsfor each project. The ratio of EUR to Total Initially-in-Place quantities defines the ultimate recovery efficiencyfor the development project(s). A project may be defined at various levels and stages of maturity; it mayinclude one or many wells and associated production and processing facilities. One project may developmany reservoirs, or many projects may be applied to one reservoir.

The Property (lease or license area): Each property may have unique associated contractual rights andobligations including the fiscal terms. Such information allows definition of each participants share ofproduced quantities (entitlement) and share of investments, expenses, and revenues for each recoveryproject and the reservoir to which it is applied. One property may encompass many reservoirs, or onereservoir may span several different properties. A property may contain both discovered and undiscoveredaccumulations.

In context of this data relationship, project is the primary element considered in this resources classification, andnet recoverable resources are the incremental quantities derived from each project. Project represents the linkbetween the petroleum accumulation and the decision-making process. A project may, for example, constitute thedevelopment of a single reservoir or field, or an incremental development for a producing field, or the integrateddevelopment of several fields and associated facilities with a common ownership. In general, an individual projectwill represent the level at which a decision is made whether or not to proceed (i.e., spend more money) and there

should be an associated range of estimated recoverable quantities for that project.


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An accumulation or potential accumulation of petroleum may be subject to several separate and distinct projectsthat are at different stages of exploration or development. Thus, an accumulation may have recoverable quantitiesin several resource classes simultaneously.

In order to assign recoverable resources of any class, a development plan needs to be defined consisting of oneor more projects. Even for Prospective Resources, the estimates of recoverable quantities must be stated in termsof the sales products derived from a development program assuming successful discovery and commercialdevelopment. Given the major uncertainties involved at this early stage, the development program will not be ofthe detail expected in later stages of maturity. In most cases, recovery efficiency may be largely based onanalogous projects. In-place quantities for which a feasible project cannot be defined using current, or reasonablyforecast improvements in, technology are classified as Unrecoverable.

Not all technically feasible development plans will be commercial. The commercial viability of a developmentproject is dependent on a forecast of the conditions that will exist during the time period encompassed by theprojects activities (see Commercial Evaluations, section 3.1). Conditions include technological, economic, legal,environmental, social, and governmental factors. While economic factors can be summarized as forecast costsand product prices, the underlying influences include, but are not limited to, market conditions, transportation andprocessing infrastructure, fiscal terms, and taxes.

The resource quantities being estimated are those volumes producible from a project as measured according todelivery specifications at the point of sale or custody transfer (see Reference Point, section 3.2.1). Thecumulative production from the evaluation date forward to cessation of production is the remaining recoverablequantity. The sum of the associated annual net cash flows yields the estimated future net revenue. Whenthe cash flows are discounted according to a defined discount rate and time period, the summation of thediscounted cash flows is termed net present value (NPV) of the project (see Evaluation and ReportingGuidelines, section 3.0).

The supporting data, analytical processes, and assumptions used in an evaluation should be documented insufficient detail to allow an independent evaluator or auditor to clearly understand the basis for estimation andcategorization of recoverable quantities and their classification.

2.0 Classification and Categorization Guidelines

2.1 Resources Classification

The basic classification requires establishment of criteria for a petroleum discovery and thereafter the distinctionbetween commercial and sub-commercial projects in known accumulations (and hence between Reserves andContingent Resources).

2.1.1 Determination of Discovery Status

A discovery is one petroleum accumulation, or several petroleum accumulations collectively, for which one orseveral exploratory wells have established through testing, sampling, and/or logging the existence of a significantquantity of potentially moveable hydrocarbons.

In this context, significant implies that there is evidence of a sufficient quantity of petroleum to justify estimatingthe in-place volume demonstrated by the well(s) and for evaluating the potential for economic recovery. Estimatedrecoverable quantities within such a discovered (known) accumulation(s) shall initially be classified as ContingentResources pending definition of projects with sufficient chance of commercial development to reclassify all, or aportion, as Reserves. Where in-place hydrocarbons are identified but are not considered currently recoverable,such quantities may be classified as Discovered Unrecoverable, if considered appropriate for resourcemanagement purposes; a portion of these quantities may become recoverable resources in the future ascommercial circumstances change or technological developments occur.


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2.1.2 Determination of CommercialityDiscovered recoverable volumes (Contingent Resources) may be considered commercially producible, and thusReserves, if the entity claiming commerciality has demonstrated firm intention to proceed with development andsuch intention is based upon all of the following criteria:

Evidence to support a reasonable timetable for development.

A reasonable assessment of the future economics of such development projects meeting defined investmentand operating criteria.

A reasonable expectation that there will be a market for all or at least the expected sales quantities ofproduction required to justify development.

Evidence that the necessary production and transportation facilities are available or can be made available.

Evidence that legal, contractual, environmental and other social and economic concerns will allow for theactual implementation of the recovery project being evaluated.

To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability.There must be a reasonable expectation that all required internal and external approvals will be forthcoming, andthere is evidence of firm intention to proceed with development within a reasonable time frame. A reasonable timeframe for the initiation of development depends on the specific circumstances and varies according to the scope ofthe project. While 5 years is recommended as a benchmark, a longer time frame could be applied where, forexample, development of economic projects are deferred at the option of the producer for, among other things,market-related reasons, or to meet contractual or strategic objectives. In all cases, the justification for classificationas Reserves should be clearly documented.

To be included in the Reserves class, there must be a high confidence in the commercial producibility of thereservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on thebasis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and isanalogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on

formation tests.

2.2 Resources Categorization

The horizontal axis in the Resources Classification (Figure 1.1) defines the range of uncertainty in estimates of thequantities of recoverable, or potentially recoverable, petroleum associated with a project. These estimates includeboth technical and commercial uncertainty components as follows:

The total petroleum remaining within the accumulation (in-place resources).

That portion of the in-place petroleum that can be recovered by applying a defined development project orprojects.

Variations in the commercial conditions that may impact the quantities recovered and sold (e.g., marketavailability, contractual changes).

Where commercial uncertainties are such that there is significant risk that the complete project (as initially defined)will not proceed, it is advised to create a separate project classified as Contingent Resources with an appropriatechance of commerciality.

2.2.1 Range of Uncertainty

The range of uncertainty of the recoverable and/or potentially recoverable volumes may be represented by eitherdeterministic scenarios or by a probability distribution (see Deterministic and Probabilistic Methods, section 4.2).

When the range of uncertainty is represented by a probability distribution, a low, best, and high estimate shall beprovided such that:

There should be at least a 90% probability (P90) that the quantities actually recovered will equal or exceed

the low estimate.


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There should be at least a 50% probability (P50) that the quantities actually recovered will equal or exceedthe best estimate.

There should be at least a 10% probability (P10) that the quantities actually recovered will equal or exceedthe high estimate.

When using the deterministic scenario method, typically there should also be low, best, and high estimates, wheresuch estimates are based on qualitative assessments of relative uncertainty using consistent interpretationguidelines. Under the deterministic incremental (risk-based) approach, quantities at each level of uncertainty areestimated discretely and separately (see Category Definitions and Guidelines, section 2.2.2).

These same approaches to describing uncertainty may be applied to Reserves, Contingent Resources, andProspective Resources. While there may be significant risk that sub-commercial and undiscovered accumulationswill not achieve commercial production, it is useful to consider the range of potentially recoverable quantitiesindependently of such a risk or consideration of the resource class to which the quantities will be assigned.

2.2.2 Category Definitions and Guidelines

Evaluators may assess recoverable quantities and categorize results by uncertainty using the deterministicincremental (risk-based) approach, the deterministic scenario (cumulative) approach, or probabilistic methods (see2001 Supplemental Guidelines, Chapter 2.5). In many cases, a combination of approaches is used.

Use of consistent terminology (Figure 1.1) promotes clarity in communication of evaluation results. For Reserves,the general cumulative terms low/best/high estimates are denoted as 1P/2P/3P, respectively. The associatedincremental quantities are termed Proved, Probable and Possible. Reserves are a subset of, and must be viewedwithin context of, the complete resources classification system. While the categorization criteria are proposedspecifically for Reserves, in most cases, they can be equally applied to Contingent and Prospective Resourcesconditional upon their satisfying the criteria for discovery and/or development.

For Contingent Resources, the general cumulative terms low/best/high estimates are denoted as 1C/2C/3Crespectively. For Prospective Resources, the general cumulative terms low/best/high estimates still apply. Nospecific terms are defined for incremental quantities within Contingent and Prospective Resources.

Without new technical information, there should be no change in the distribution of technically recoverablevolumes and their categorization boundaries when conditions are satisfied sufficiently to reclassify a project fromContingent Resources to Reserves. All evaluations require application of a consistent set of forecast conditions,including assumed future costs and prices, for both classification of projects and categorization of estimatedquantities recovered by each project (see Commercial Evaluations, section 3.1).

Based on additional data and updated interpretations that indicate increased certainty, portions of Possible andProbable Reserves may be re-categorized as Probable and Proved Reserves.

Uncertainty in resource estimates is best communicated by reporting a range of potential results. However, if it isrequired to report a single representative result, the best estimate is considered the most realistic assessment ofrecoverable quantities. It is generally considered to represent the sum of Proved and Probable estimates(2P) when using the deterministic scenario or the probabilistic assessment methods. It should be noted that underthe deterministic incremental (risk-based) approach, discrete estimates are made for each category, and theyshould not be aggregated without due consideration of their associated risk (see 2001 Supplemental Guidelines,Chapter 2.5).


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Table 1: Recoverable Resources Classes and Sub-Classes

Class/Sub-Class Definition Guidelines

Reserves Reserves are those quantities ofpetroleum anticipated to becommercially recoverable byapplication of development projectsto known accumulations from agiven date forward under definedconditions.

Reserves must satisfy four criteria: they must be discovered,recoverable, commercial, and remaining based on thedevelopment project(s) applied. Reserves are furthersubdivided in accordance with the level of certaintyassociated with the estimates and may be sub-classifiedbased on project maturity and/or characterized by theirdevelopment and production status.

To be included in the Reserves class, a project must besufficiently defined to establish its commercial viability. Theremust be a reasonable expectation that all required internal

and external approvals will be forthcoming, and there isevidence of firm intention to proceed with development withina reasonable time frame.

A reasonable time frame for the initiation of developmentdepends on the specific circumstances and varies accordingto the scope of the project. While 5 years is recommendedas a benchmark, a longer time frame could be appliedwhere, for example, development of economic projects aredeferred at the option of the producer for, among otherthings, market-related reasons, or to meet contractual orstrategic objectives. In all cases, the justification forclassification as Reserves should be clearly documented.

To be included in the Reserves class, there must be a highconfidence in the commercial producibility of the reservoir assupported by actual production or formation tests. In certaincases, Reserves may be assigned on the basis of well logsand/or core analysis that indicate that the subject reservoir ishydrocarbon-bearing and is analogous to reservoirs in thesame area that are producing or have demonstrated theability to produce on formation tests.

On Production The development project is currentlyproducing and selling petroleum tomarket.

The key criterion is that the project is receiving income fromsales, rather than the approved development projectnecessarily being complete. This is the point at which theproject chance of commerciality can be said to be 100%.

The project decision gate is the decision to initiatecommercial production from the project.

Approved for

Development

All necessary approvals have been

obtained, capital funds have beencommitted, and implementation ofthe development project is underway.

At this point, it must be certain that the development project

is going ahead. The project must not be subject to anycontingencies such as outstanding regulatory approvals orsales contracts. Forecast capital expenditures should beincluded in the reporting entitys current or following yearsapproved budget.

The project decision gate is the decision to start investingcapital in the construction of production facilities and/ordrilling development wells.


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Class/Sub-Class Definition GuidelinesJustified forDevelopment

Implementation of the developmentproject is justified on the basis ofreasonable forecast commercialconditions at the time of reporting,and there are reasonableexpectations that all necessaryapprovals/contracts will be obtained.

In order to move to this level of project maturity, and hencehave reserves associated with it, the development projectmust be commercially viable at the time of reporting, basedon the reporting entitys assumptions of future prices, costs,etc. (forecast case) and the specific circumstances of theproject. Evidence of a firm intention to proceed withdevelopment within a reasonable time frame will be sufficientto demonstrate commerciality. There should be adevelopment plan in sufficient detail to support theassessment of commerciality and a reasonable expectationthat any regulatory approvals or sales contracts requiredprior to project implementation will be forthcoming. Otherthan such approvals/contracts, there should be no knowncontingencies that could preclude the development from

proceeding within a reasonable timeframe (see Reservesclass).

The project decision gate is the decision by the reportingentity and its partners, if any, that the project has reached alevel of technical and commercial maturity sufficient to justifyproceeding with development at that point in time.

ContingentResources

Those quantities of petroleumestimated, as of a given date, to bepotentially recoverable from knownaccumulations by application ofdevelopment projects, but which arenot currently considered to becommercially recoverable due toone or more contingencies.

Contingent Resources may include, for example, projects forwhich there are currently no viable markets, or wherecommercial recovery is dependent on technology underdevelopment, or where evaluation of the accumulation isinsufficient to clearly assess commerciality. ContingentResources are further categorized in accordance with thelevel of certainty associated with the estimates and may besub-classified based on project maturity and/or characterizedby their economic status.

Development Pending A discovered accumulation whereproject activities are ongoing to

justify commercial development inthe foreseeable future.

The project is seen to have reasonable potential for eventualcommercial development, to the extent that further dataacquisition (e.g. drilling, seismic data) and/or evaluations arecurrently ongoing with a view to confirming that the project iscommercially viable and providing the basis for selection ofan appropriate development plan. The critical contingencieshave been identified and are reasonably expected to beresolved within a reasonable time frame. Note thatdisappointing appraisal/evaluation results could lead to a re-classification of the project to On Hold or Not Viablestatus.

The project decision gate is the decision to undertakefurther data acquisition and/or studies designed to move theproject to a level of technical and commercial maturity at

which a decision can be made to proceed with developmentand production.

DevelopmentUnclarified or on Hold

A discovered accumulation whereproject activities are on hold and/orwhere justification as a commercialdevelopment may be subject tosignificant delay.

The project is seen to have potential for eventual commercialdevelopment, but further appraisal/evaluation activities areon hold pending the removal of significant contingenciesexternal to the project, or substantial further appraisal/evaluation activities are required to clarify the potential foreventual commercial development. Development may besubject to a significant time delay. Note that a change incircumstances, such that there is no longer a reasonableexpectation that a critical contingency can be removed in theforeseeable future, for example, could lead to areclassification of the project to Not Viable status.


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Class/Sub-Class Definition GuidelinesThe project decision gate is the decision to either proceedwith additional evaluation designed to clarify the potential foreventual commercial development or to temporarily suspendor delay further activities pending resolution of externalcontingencies.

Development NotViable

A discovered accumulation for whichthere are no current plans todevelop or to acquire additional dataat the time due to limited productionpotential.

The project is not seen to have potential for eventualcommercial development at the time of reporting, but thetheoretically recoverable quantities are recorded so that thepotential opportunity will be recognized in the event of amajor change in technology or commercial conditions.

The project decision gate is the decision not to undertake

any further data acquisition or studies on the project for theforeseeable future.

Prospective

Resources

Those quantities of petroleum whichare estimated, as of a given date, tobe potentially recoverable fromundiscovered accumulations.

Potential accumulations are evaluated according to theirchance of discovery and, assuming a discovery, theestimated quantities that would be recoverable under defineddevelopment projects. It is recognized that the developmentprograms will be of significantly less detail and depend moreheavily on analog developments in the earlier phases ofexploration.

Prospect A project associated with a potentialaccumulation that is sufficiently welldefined to represent a viable drillingtarget.

Project activities are focused on assessing the chance ofdiscovery and, assuming discovery, the range of potentialrecoverable quantities under a commercial developmentprogram.

Lead A project associated with a potential

accumulation that is currently poorlydefined and requires more dataacquisition and/or evaluation inorder to be classified as a prospect.

Project activities are focused on acquiring additional data

and/or undertaking further evaluation designed to confirmwhether or not the lead can be matured into a prospect.Such evaluation includes the assessment of the chance ofdiscovery and, assuming discovery, the range of potentialrecovery under feasible development scenarios.

Play A project associated with aprospective trend of potentialprospects, but which requires moredata acquisition and/or evaluation inorder to define specific leads orprospects.

Project activities are focused on acquiring additional dataand/or undertaking further evaluation designed to definespecific leads or prospects for more detailed analysis of theirchance of discovery and, assuming discovery, the range ofpotential recovery under hypothetical developmentscenarios.

Table 2: Reserves Status Definitions and Guidelines

Status Definition Guidelines

Developed

Reserves

Developed Reserves areexpected quantities to berecovered from existing wells andfacilities.

Reserves are considered developed only after the necessaryequipment has been installed, or when the costs to do so arerelatively minor compared to the cost of a well. Where requiredfacilities become unavailable, it may be necessary to reclassifyDeveloped Reserves as Undeveloped. Developed Reservesmay be further sub-classified as Producing or Non-Producing.

Developed ProducingReserves

Developed Producing Reservesare expected to be recoveredfrom completion intervals that areopen and producing at the time ofthe estimate.

Improved recovery reserves are considered producing onlyafter the improved recovery project is in operation.


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Status Definition Guidelines

Developed Non-Producing Reserves

Developed Non-ProducingReserves include shut-in andbehind-pipe Reserves.

Shut-in Reserves are expected to be recovered from (1)completion intervals which are open at the time of the estimatebut which have not yet started producing, (2) wells which wereshut-in for market conditions or pipeline connections, or (3)wells not capable of production for mechanical reasons.Behind-pipe Reserves are expected to be recovered fromzones in existing wells which will require additional completionwork or future re-completion prior to start of production.

In all cases, production can be initiated or restored withrelatively low expenditure compared to the cost of drilling a newwell.

Undeveloped

Reserves

Undeveloped Reserves are

quantities expected to berecovered through futureinvestments:

(1) from new wells on undril led acreage in known

accumulations, (2) from deepening existing wells to a different(but known) reservoir, (3) from infill wells that will increaserecovery, or (4) where a relatively large expenditure (e.g. whencompared to the cost of drilling a new well) is required to (a)recomplete an existing well or (b) install production ortransportation facilities for primary or improved recoveryprojects.

Table 3: Reserves Category Definitions and Guidelines

Category Definition Guidelines

Proved Reserves Proved Reserves are those

quantities of petroleum, which byanalysis of geoscience andengineering data, can beestimated with reasonablecertainty to be commerciallyrecoverable, from a given dateforward, from known reservoirsand under defined economicconditions, operating methods,and government regulations.

If deterministic methods are used, the term reasonable certainty

is intended to express a high degree of confidence that thequantities will be recovered. If probabilistic methods are used,there should be at least a 90% probability that the quantitiesactually recovered will equal or exceed the estimate.

The area of the reservoir considered as Proved includes (1) thearea delineated by drilling and defined by fluid contacts, if any,and (2) adjacent undrilled portions of the reservoir that canreasonably be judged as continuous with it and commerciallyproductive on the basis of available geoscience andengineering data.

In the absence of data on fluid contacts, Proved quantities in areservoir are limited by the lowest known hydrocarbon (LKH) as

seen in a well penetration unless otherwise indicated bydefinitive geoscience, engineering, or performance data. Suchdefinitive information may include pressure gradient analysisand seismic indicators. Seismic data alone may not besufficient to define fluid contacts for Proved reserves (see 2001Supplemental Guidelines, Chapter 8).

Reserves in undeveloped locations may be classified as Provedprovided that:

The locations are in undrilled areas of the reservoir that canbe judged with reasonable certainty to be commerciallyproductive.

Interpretations of available geoscience and engineering dataindicate with reasonable certainty that the objectiveformation is laterally continuous with drilled Proved locations.


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Category Definition Guidelines

For Proved Reserves, the recovery efficiency applied to thesereservoirs should be defined based on a range of possibilitiessupported by analogs and sound engineering judgmentconsidering the characteristics of the Proved area and theapplied development program.

Probable

Reserves

Probable Reserves are thoseadditional Reserves whichanalysis of geoscience andengineering data indicate are lesslikely to be recovered thanProved Reserves but morecertain to be recoveredthan Possible Reserves.

It is equally likely that actual remaining quantities recovered willbe greater than or less than the sum of the estimated Provedplus Probable Reserves (2P). In this context, when probabilisticmethods are used, there should be at least a 50% probabilitythat the actual quantities recovered will equal or exceed the 2Pestimate.

Probable Reserves may be assigned to areas of a reservoir

adjacent to Proved where data control or interpretations ofavailable data are less certain. The interpreted reservoircontinuity may not meet the reasonable certainty criteria.

Probable estimates also include incremental recoveriesassociated with project recovery efficiencies beyond thatassumed for Proved.

Possible

Reserves

Possible Reserves are thoseadditional reserves whichanalysis of geoscience andengineering data indicate are lesslikely to be recoverable thanProbable Reserves.

The total quantities ultimately recovered from the project have alow probability to exceed the sum of Proved plus Probable plusPossible (3P), which is equivalent to the high estimate scenario.When probabilistic methods are used, there should be at least a10% probability that the actual quantities recovered will equal orexceed the 3P estimate.

Possible Reserves may be assigned to areas of a reservoiradjacent to Probable where data control and interpretations ofavailable data are progressively less certain. Frequently, thismay be in areas where geoscience and engineering data areunable to clearly define the area and vertical reservoir limits ofcommercial production from the reservoir by a defined project.

Possible estimates also include incremental quantitiesassociated with project recovery efficiencies beyond thatassumed for Probable.

Probable and

Possible

Reserves

(See above for separate criteriafor Probable Reserves andPossible Reserves.)

The 2P and 3P estimates may be based on reasonablealternative technical and commercial interpretations within thereservoir and/or subject project that are clearly documented,including comparisons to results in successful similar projects.

In conventional accumulations, Probable and/or PossibleReserves may be assigned where geoscience and engineeringdata identify directly adjacent portions of a reservoir within thesame accumulation that may be separated from Proved areasby minor faulting or other geological discontinuities and havenot been penetrated by a wellbore but are interpreted to be incommunication with the known (Proved) reservoir. Probable orPossible Reserves may be assigned to areas that arestructurally higher than the Proved area. Possible (and in somecases, Probable) Reserves may be assigned to areas that arestructurally lower than the adjacent Proved or 2P area.


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Category Definition GuidelinesCaution should be exercised in assigning Reserves to adjacentreservoirs isolated by major, potentially sealing, faults until thisreservoir is penetrated and evaluated as commerciallyproductive. Justification for assigning Reserves in such casesshould be clearly documented. Reserves should not beassigned to areas that are clearly separated from a knownaccumulation by non-productive reservoir (i.e., absence ofreservoir, structurally low reservoir, or negative test results);such areas may contain Prospective Resources.

In conventional accumulations, where drilling has defined ahighest known oil (HKO) elevation and there exists the potentialfor an associated gas cap, Proved oil Reserves should only beassigned in the structurally higher portions of the reservoir if

there is reasonable certainty that such portions are initiallyabove bubble point pressure based on documentedengineering analyses. Reservoir portions that do not meet thiscertainty may be assigned as Probable and Possible oil and/orgas based on reservoir fluid properties and pressure gradientinterpretations.

The 2007 Petroleum Resources Management System can be viewed in its entirety at

http://www.spe.org/spe-app/spe/industry/reserves/prms.htm.


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SUMMARY OF RESERVES AND FUTURE NET REVENUE

KRISENERGY LTD INTEREST

AS OF DECEMBER 31, 2012

Gross Reserves(1)Working Interest

Reserves(2) Net Reserves(3) Future Net Revenue(4) (M$)

Country/Asset/Category Oil(MBBL) Gas(MMCF) Oil(MBBL) Gas(MMCF) Oil(MBBL) Gas(MMCF) Total Present Worthat 10%

Offshore Thailand

Blocks B8/32 and B9AProved Developed Producing 21,286.2 66,016.4 986.5 3,059.5 899.2 2,863.3 (13,700.9)(5) (408.6)(5)

Proved Undeveloped 21,019.0 78,558.5 974.1 3,640.8 854.1 3,367.4 69,407.3 53,452.1

Proved (1P) 42,305.1 144,574.8 1,960.6 6,700.3 1,753.3 6,230.7 55,706.4 53,043.5

Probable 107,336.7 685,214.4 4,974.5 31,756.3 4,379.0 28,595.0 206,777.0 109,082.4

Proved + Probable (2P) 149,641.8 829,789.3 6,935.1 38,456.6 6,132.2 34,825.7 262,483.5 162,125.9

Possible 32,097.2 221,026.4 1,487.5 10,243.5 1,273.7 8,906.5 92,186.9 45,010.2

Proved + Probable + Possible (3P) 181,739.0 1,050,815.7 8,422.7 48,700.1 7,405.9 43,732.2 354,670.4 207,136.1

Block G11/48, Nong Yao Field

Probable 15,100.0 0.0 3,775.0 0.0 3,115.0 0.0 73,205.3 54,444.6

Proved + Probable (2P) 15,100.0 0.0 3,775.0 0.0 3,115.0 0.0 73,205.3 54,444.6

Possible 7,900.0 0.0 1,975.0 0.0 1,618.8 0.0 41,269.2 25,678.0

Proved + Probable + Possible (3P) 23,000.0 0.0 5,750.0 0.0 4,733.9 0.0 114,474.5 80,122.6

Offshore Indonesia

Kambuna FieldProved Developed Producing 44.8 555.0 11.2 138.8 8.3 120.5 27.1 25.9

Proved (1P) 44.8 555.0 11.2 138.8 8.3 120.5 27.1 25.9

Probable 4.3 43.4 1.1 10.8 0.8 9.4 154.3 147.1

Proved + Probable (2P) 49.1 598.4 12.3 149.6 9.1 130.0 181.4 173.0

Possible 4.5 49.7 1.1 12.4 0.8 10.8 168.5 160.6

Proved + Probable + Possible (3P) 53.6 648.1 13.4 162.0 10.0 140.8 349.9 333.6


Note: Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production

status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

(1) Gross reserves correspond to the 100 percent interest or 8/8ths reserves.(2) KrisEnergys current working interest is 4.6345 percent in Blocks B8/32 and B9A and 25 percent in Nong Yao and Kambuna Fields. It is

anticipated that local participation will reduce the working interest in Nong Yao Field to 22.5 percent. For Nong Yao Field, working interest

reserves are estimated based on the current working interest and revenue is estimated based on the future reduced working interest.

KrisEnergy executed a share sale purchase agreement on April 8, 2013, to acquire a 30 percent working interest and operatorship in Block 9,

onshore Bangladesh. The acquisition is contingent upon the approval of Petrobangla and will have a retroactive effective date of January 1,

2013. As requested, working interest reserves for Block 9 are estimated based on the interest expected to be owned when all approvals are

finalized.(3) Net reserves are the portion of gross reserves representing KrisEnergys revenue entitlement.(4) Future net revenue is after deductions for royalties and KrisEnergys share of future capital costs, abandonment costs, operating expenses,

special remuneratory benefit, training fees, and income taxes.(5) Future net revenue is negative after deducting estimated abandonment costs.

All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.

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SUMMARY OF RESERVES AND FUTURE NET REVENUE



Gross Reserves(1)Working Interest

Reserves(2) Net Reserves(3) Future Net Revenue(4) (M$)

Country/Asset/CategoryOil

(MBBL)Gas

(MMCF)Oil

(MBBL)Gas

(MMCF)Oil

(MBBL)Gas

(MMCF) TotalPresent Worth

at 10%

Onshore Bangladesh

Block 9, Bangora FieldProved Developed Producing 206.4 65,003.2 61.9 19,501.0 37.8 12,355.7 12,806.7 11,837.0Proved Developed Non-Producing 44.4 15,444.9 13.3 4,633.5 8.1 2,935.8 6,468.5 5,482.2

Proved (1P) 250.8 80,448.2 75.2 24,134.4 45.9 15,291.5 19,275.2 17,319.2

Probable 475.5 206,064.2 142.6 61,819.3 59.0 36,175.8 42,188.9 26,124.4

Proved + Probable (2P) 726.3 286,512.4 217.9 85,953.7 104.9 51,467.3 61,464.1 43,443.6

Possible 406.1 140,996.4 121.8 42,298.9 44.6 22,065.6 29,165.0 12,822.6

Proved + Probable + Possible (3P) 1,132.4 427,508.8 339.7 128,252.6 149.5 73,532.9 90,629.1 56,266.2

Total

Proved Developed Producing 21,537.4 131,574.6 1,059.6 22,699.3 945.3 15,339.5 (867.0)(5) 11,454.2Proved Developed Non-Producing 44.4 15,444.9 13.3 4,633.5 8.1 2,935.8 6,468.5 5,482.2Proved Undeveloped 21,019.0 78,558.5 974.1 3,640.8 854.1 3,367.4 69,407.3 53,452.1

Proved (1P) 42,600.8 225,578.0 2,047.1 30,973.5 1,807.5 21,642.7 75,008.8 70,388.5

Probable 122,916.4 8 91,322.0 8,893.2 93,586.4 7,553.8 64,780.3 322,325.6 189,798.6

Proved + Probable (2P) 165,517.2 1,116,900.0 10,940.3 124,559.9 9,361.3 86,423.0 397,334.4 260,187.1

Possible 40,407.8 362,072.5 3,585.5 52,554.8 2,937.9 30,982.9 162,789.5 83,671.4

Proved + Probable + Possible (3P) 205,925.0 1,478,972.5 14,525.8 177,114.7 12,299.2 117,405.9 560,123.9 343,858.5


Note: Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production

status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

(1) Gross reserves correspond to the 100 percent interest or 8/8ths reserves.(2) KrisEnergys current working interest is 4.6345 percent in Blocks B8/32 and B9A and 25 percent in Nong Yao and Kambuna Fields. It is

anticipated that local participation will reduce the working interest in Nong Yao Field to 22.5 percent. For Nong Yao Field, working interest

reserves are estimated based on the current working interest and revenue is estimated based on the future reduced working interest.

KrisEnergy executed a share sale purchase agreement on April 8, 2013, to acquire a 30 percent working interest and operatorship in Block 9,

onshore Bangladesh. The acquisition is contingent upon the approval of Petrobangla and will have a retroactive effective date of January 1,

2013. As requested, working interest reserves for Block 9 are estimated based on the interest expected to be owned when all approvals are

finalized.(3) Net reserves are the portion of gross reserves representing KrisEnergys revenue entitlement.(4) Future net revenue is after deductions for royalties and KrisEnergys share of future capital costs, abandonment costs, operating expenses,

special remuneratory benefit, training fees, and income taxes.(5) Future net revenue is negative after deducting estimated abandonment costs.


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SUMMARY OF DEVELOPMENT PENDING

CONTINGENT RESOURCES AND CASH FLOW



Gross Contingent

Resources(1)Working Interest

Contingent Resources(2)Net Contingent

Resources(3)Net Contingent

Cash Flow(4) (M$)


(MBBL)Gas

(MMCF)Oil

(MBBL)Gas

(MMCF)Oil

(MBBL)Gas

(MMCF) TotalDiscounted

at 10%

Offshore Thailand

Block G6/48, Rossukon FieldLow Estimate (1C) 3,700.0 0.0 1,110.0 0.0 1,050.8 0.0 6,077.0 109.4Best Estimate (2C) 8,374.7 0.0 2,512.4 0.0 2,356.8 0.0 49,608.5 26,187.2High Estimate (3C) 20,500.0 0.0 6,150.0 0.0 5,701.6 0.0 137,489.0 72,496.4

Block G10/48, Wassana FieldLow Estimate (1C) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Best Estimate (2C) 13,573.3 0.0 3,393.3 0.0 2,824.7 0.0 79,631.6 53,849.8High Estimate (3C) 21,900.0 0.0 5,475.0 0.0 4,506.2 0.0 123,453.3 80,750.3

Block G10/48, Niramai FieldLow Estimate (1C) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Best Estimate (2C) 4,900.0 0.0 1,225.0 0.0 969.1 0.0 7,483.1 2,602.9High Estimate (3C) 7,100.0 0.0 1,775.0 0.0 1,390.0 0.0 10,498.4 4,343.0

Offshore Indonesia

Bulu PSC, Lengo FieldLow Estimate (1C) 0.0 180,500.0 0.0 76,712.5 0.0 54,539.2 70,965.6 18,215.4Best Estimate (2C) 0.0 227,000.0 0.0 96,475.0 0.0 64,846.4 99,212.4 33,253.7High Estimate (3C) 0.0 283,048.2 0.0 1 20,295.5 0.0 77,090.9 133,462.4 50,244.8

East Muriah PSC, East Lengo FieldLow Estimate (1C) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Best Estimate (2C) 0.0 19,644.4 0.0 9,822.2 0.0 8,019.1 8,964.3 1,574.3High Estimate (3C) 0.0 48,860.9 0.0 24,430.4 0.0 15,995.3 31,032.3 11,559.6

Kutai PSC, Dambus and MangkokFieldsLow Estimate (1C) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Best Estimate (2C) 90.1 75,680.7 49.2 41,321.6 39.8 27,375.3 70,863.1 34,955.2High Estimate (3C) 146.8 117,476.3 80.2 64,142.0 64.9 38,035.4 110,014.8 51,483.4

Offshore Cambodia

Block A, Platform ALow Estimate (1C) 4,900.0 0.0 1,163.8 0.0 975.5 0.0 16,611.7 3,467.0Best Estimate (2C) 8,600.0 0.0 2,042.5 0.0 1,600.0 0.0 61,833.1 30,938.7High Estimate (3C) 14,952.7 0.0 3,551.3 0.0 2,446.4 0.0 114,036.6 60,180.9

Total(5)

Low Estimate (1C) 8,600.0 180,500.0 2,273.8 76,712.5 2,026.3 54,539.2 93,654.3 21,791.8Best Estimate (2C) 35,538.1 322,325.0 9,222.4 147,618.8 7,790.4 100,240.8 377,595.9 183,361.8High Est imate (3C) 64,599.5 449,385.3 17,031.4 208,868.0 14,109.1 131,121.6 659,986.8 331,058.3


(1) Gross contingent resources correspond to the 100 percent interest or 8/8ths resources.(2) KrisEnergys current working interest is 25 percent in Block G10/48, 42.5 percent in the Bulu PSC, 50 percent in the East Muriah PSC,

54.6 percent in the Kutai PSC, and 23.75 percent in Block A. It is anticipated that local participation will reduce the current working interest

proportionately in each asset based on the local participant obtaining 10 percent, except for Block A. Where applicable, working interest

contingent resources are estimated based on the current working interest and net contingent cash flows are estimated based on the future

reduced working interest. KrisEnergy signed a farm-out agreement on March 15, 2013, to acquire a 30 percent working interest and

operatorship in Block G6/48, Gulf of Thailand. The transaction is pending approval by the Thailand government and will have a retroactiveeffective date of January 1, 2013. As requested, working interest contingent resources for Block G6/48 are estimated based on the interest

expected to be owned when all approvals are finalized.(3) Net contingent resources are the portion of gross resources representing KrisEnergys cash flow entitlement.(4) Net contingent cash flow is after deductions for royalties and KrisEnergys share of future capital costs, abandonment costs, operating

expenses, special remuneratory benefit, and income taxes.(5) Totals are the arithmetic sum of multiple asset-level probability distributions.


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SUMMARY OF DEVELOPMENT UNCLARIFIED

CONTINGENT RESOURCES



Gross ContingentResources(1)

Working InterestContingent Resources(2)


(MBBL)Gas

(MMCF)Oil

(MBBL)Gas

(MMCF)

Offshore Thailand

Block G10/48, Mayura FieldLow Estimate (1C) 453.7 0.0 113.4 0.0Best Estimate (2C) 1,140.3 0.0 285.1 0.0High Estimate (3C) 3,124.7 0.0 781.2 0.0

Block G11/48, Angun FieldLow Estimate (1C) 285.1 0.0 71.3 0.0Best Estimate (2C) 663.8 0.0 166.0 0.0High Estimate (3C) 21,066.8 0.0 5,266.7 0.0

Block G11/48, Mantana FieldLow Estimate (1C) 0.0 4,922.7 0.0 1,230.7Best Estimate (2C) 0.0 14,842.6 0.0 3,710.7High Estimate (3C) 0.0 26,077.9 0.0 6,519.5

Offshore Indonesia

Tanjung Aru PSC, Halimun and Papandayan FieldsLow Estimate (1C) 0.0 0.0 0.0 0.0Best Estimate (2C

KrisEnergy Ltd - Appendix D_Volume1

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