FORM 51-101F1

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

For the Year Ended December 31, 2012

March 28, 2013

TABLE OF CONTENTS PART 1: INTRODUCTION ....................................................................................................................... 4 PART 2: DISCLOSURE OF RESERVES DATA .................................................................................... 5

2.1 Reserves Data ...................................................................................................................................... 5 PART 3: PRICING ASSUMPTIONS ........................................................................................................ 8

3.1 Forecast Prices Used in Estimates ....................................................................................................... 8 PART 4: RECONCILIATIONS OF CHANGES IN RESERVES AND FUTURE NET REVENUE .. 9

4.1 Reserves Reconciliation ....................................................................................................................... 9 PART 5: ADDITIONAL INFORMATION RELATING TO RESERVES DATA ............................. 10

5.1 Undeveloped Reserves....................................................................................................................... 10 5.2 Significant Factors or Uncertainties .................................................................................................. 11 5.3 Future Development Costs ................................................................................................................ 12

5.4 Disclosure Resources ......................................................................................................................... 13

PART 6: OTHER OIL AND GAS INFORMATION ............................................................................. 14 6.1 Oil and Gas Properties and Wells ...................................................................................................... 14 6.2 Properties with No Attributed Reserves ............................................................................................ 16 6.3 Forward Contracts ............................................................................................................................. 16 6.4 Additional Information Concerning Abandonment and Reclamation Costs ..................................... 16 6.5 Tax Horizon ....................................................................................................................................... 17 6.6 Costs Incurred .................................................................................................................................... 17 6.7 Exploration and Development Activities ........................................................................................... 18 6.8 Production Estimates ......................................................................................................................... 19 6.9 Production History ............................................................................................................................. 20

PART 7: NOTES ....................................................................................................................................... 20

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GLOSSARY OF TERMS

“Addendum” means the Addendum to the Plan of Development for the Patos-Marinza oilfield submitted by Bankers Albania to Albpetrol and the AKBN;

“AKBN” means the National Agency for Natural Resources in Albania;

“AIF” refers to the Company’s Annual Information Form filed on SEDAR;

“AIM” means the Alternative Investment Market of the London Stock Exchange;

“AIT” means ‘After Income Taxes’;

“Albpetrol” means Albpetrol Sh.A, the Albanian state-owned oil and gas company;

“API” is an indication of the specific gravity of crude oil measured on the American Petroleum Institute gravity scale;

“ARMO” means ARMO Sh.A, the Albanian Refining and Marketing Organization;

“Bankers” means Bankers Petroleum Ltd.;

“Bankers Albania” means Bankers Petroleum Albania Ltd., formerly Saxon International Energy Ltd., a subsidiary of the Company;

“BIT” means ‘Before Income Taxes’;

“Company” means Bankers Petroleum Ltd.;

“D&M” means DeGolyer and MacNaughton Canada Limited, independent petroleum engineering consultants of Calgary, Alberta;

“License Agreement” refers to the agreement between AKBN and Albpetrol to which Bankers became a party;

“NI 51-101” refers to National Instrument 51-101;

“Petroleum Agreement” refers to the agreement between Bankers and Albpetrol that governs the Company’s ownership and production sharing terms in the Patos-Marinza heavy oilfield;

“Petroleum-Initially-In-Place (PIIP)” in this filing represents “Original-Oil-In-Place (OOIP)”;

“PoD” means the Plan of Development for the Patos-Marinza oilfield;

“RPS” means RPS Energy Canada Ltd., independent petroleum engineering consultants of Calgary, Alberta;

“Sherwood” means Sherwood International Petroleum Ltd., a subsidiary of the Company; and

“TSX” means the Toronto Stock Exchange.

Abbreviations

API American Petroleum Institute Bbl Barrel Bbls Barrels Bopd Barrels of oil per day Mbbls Thousand barrels MMbbls Million barrels Brent Brent crude oil

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PART 1: INTRODUCTION The effective date of the information being provided in this statement is December 31, 2012. The preparation date of the information being provided in this statement is March 28, 2013. For a glossary of terminology and definitions relating to the information included within this statement (including the aforementioned dates), readers are referred to NI 51-101. Reserves and Future Net Revenue

The following is a summary of the oil reserves and the net present values of future net revenue of Bankers Petroleum Ltd.’s wholly owned subsidiaries Bankers Petroleum Albania Ltd. and Sherwood International Petroleum Ltd. as evaluated by RPS and D&M, respectively. The Company’s properties with assigned reserves are (1) the Patos-Marinza oilfield in Albania and (2) the Kuçova oilfield in Albania. RPS and D&M are independent qualified reserves evaluators appointed by the Company pursuant to NI 51-101. All of the Company’s oil properties are located in Albania. Albanian taxes throughout this evaluation are based on projected cash flows, assuming no financing charges. The estimated future net revenue figures contained in the following tables do not necessarily represent the fair market value of the Company's reserves. There is no assurance that the forecast price and cost assumptions contained in either the RPS or D&M Reports will be attained and variances could be material. Other assumptions relating to costs and other matters are included in the RPS Report and the D&M Report. The recovery and reserve estimates attributed to the Company's properties described herein are estimates only. The actual reserves attributed to the Company's properties may be greater or less than those calculated. All dollar values are expressed in US dollars, unless otherwise indicated. Readers should note that totals in the following tables may not add due to rounding. Cautionary Statements

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 the proved, probable plus possible reserves.

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PART 2: DISCLOSURE OF RESERVES DATA 2.1 Reserves Data

Summary of Oil Reserves

As of December 31, 2012

Forecast Prices & Costs

Heavy Oil

Patos-Marinza Kuçova Total Albania

Reserve Category Gross (MMbbl) Net (MMbbl) Gross (MMbbl) Net (MMbbl) Gross (MMbbl) Net (MMbbl)

Proved

Developed Producing 25.4 20.0 - - 25.4 20.0

Developed Non-Producing 3.0 2.6 - - 3.0 2.6

Undeveloped 107.6 93.6 3.4 2.2 111.0 95.8

Total Proved 136.0 116.3 3.4 2.2 139.4 118.4

Probable 77.8(1) 67.1 8.5 7.3 86.3 74.4

Total Proved plus Probable 213.8 183.4 11.9 9.5 225.7 192.8

Possible 110.8 95.0 21.5 18.4 132.3 113.4 Total Proved, Probable

plus Possible 324.6 278.4 33.4 27.9 358.0 306.2

(1) Includes probable developed (17.5 MMbbl) and probable undeveloped (60.3 MMbbl)

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Net Present Value of Future Net RevenueAs of December 31, 2012Forecast Prices & Costs

Net Present Value of Future Net Revenue ($ millions) Before Income Taxes After Income Taxes Reserve Category 0% 5% 10% 15% 20% 0% 5% 10% 15% 20% Patos-Marinza

Proved

Developed Producing 705 619 552 498 455 451 407 372 343 319

Developed Non-Producing 116 98 84 74 67 59 50 44 39 35

Undeveloped 2,574 1,463 847 490 275 1,539 884 517 301 170

Total Proved 3,396 2,180 1,483 1,062 796 2,050 1,341 932 683 524

Probable 4,620 2,431 1,454 961 684 2,543 1,334 793 521 369

Total Proved plus Probable 8,016 4,611 2,937 2,023 1,480 4,593 2,675 1,724 1,203 892

Possible 8,176 3,154 1,566 932 627 4,576 1,748 860 507 340 Total Proved, Probable

plus Possible 16,192 7,764 4,504 2,955 2,107 9,168 4,423 2,584 1,711 1,232 Kuçova

Proved

Developed Producing - - - - - - - - - -

Developed Non-Producing - - - - - - - - - -

Undeveloped 124 58 30 17 10 98 48 26 14 8

Total Proved 124 58 30 17 10 98 48 26 14 8

Probable 407 259 165 105 68 284 181 115 75 48

Total Proved plus Probable 531 317 195 122 78 382 229 141 89 56

Possible 1,290 798 519 354 251 867 539 354 242 174 Total Proved, Probable

plus Possible 1,821 1,115 714 476 329 1,249 768 495 331 230 Total Albania

Proved

Developed Producing 705 619 552 498 455 451 407 372 343 319

Developed Non-Producing 116 98 84 74 67 59 50 44 39 35

Undeveloped 2,698 1,521 877 507 285 1,637 932 543 315 178

Total Proved 3,520 2,238 1,513 1,079 806 2,148 1,389 958 697 532

Probable 5,027 2,690 1,619 1,066 752 2,827 1,515 908 596 417

Total Proved plus Probable 8,547 4,928 3,132 2,145 1,558 4,975 2,904 1,865 1,292 948

Possible 9,466 3,952 2,085 1,286 878 5,443 2,287 1,214 749 514 Total Proved, Probable

plus Possible 18,013 8,879 5,218 3,431 2,436 10,417 5,191 3,079 2,042 1,462

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Total Future Net Revenue (Undiscounted – by Reserve Category) As of December 31, 2012 Forecast Prices & Costs

Reserve Category ($ millions) Revenue Royalties

Operation Costs

Development Costs

Abandonment &

Reclamation

Costs

Future Net

Revenue BIT

Income Taxes

Future Net

Revenue AIT

Patos-Marinza Total Proved 12,124 1,601 4,820 2,112 195 3,396 1,346 2,050 Total Proved plus Probable 20,155 2,636 7,200 2,076 227 8,016 3,423 4,593 Total Proved, Probable plus

Possible 32,750 4,315 9,699 2,279 265 16,192 7,024 9,168

Kuçova Total Proved 307 102 68 13 - 124 26 98 Total Proved plus Probable 998 201 148 118 - 531 150 382 Total Proved, Probable plus

Possible 2,832 464 429 118 - 1,821 572 1,249

Total Albania

Total Proved 12,431 1,703 4,888 2,125 195 3,520 1,372 2,148 Total Proved plus Probable 21,153 2,837 7,348 2,194 227 8,547 3,573 4,975 Total Proved, Probable plus

Possible 35,582 4,779 10,128 2,397 265 18,013 7,596 10,417

Total Future Net Revenue by Production Group (NPV discounted 10%, BIT)

As of December 31, 2012Forecast Prices & Costs

Patos-Marinza Kuçova Reserve Category

Heavy Oil ($ millions)

Unit Value ($/bbl)

Heavy Oil ($ millions)

Unit Value ($/bbl)

Total Proved 1,483 10.90 30 13.70 Total Proved plus Probable 2,937 13.74 195 20.57 Total Proved, Probable plus Possible 4,504 13.87 714 25.61

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PART 3: PRICING ASSUMPTIONS 3.1 Forecast Prices Used in Estimates Forecast benchmark reference product price, inflation rate and exchange rate assumptions are summarized below. These forecast assumptions were provided in the RPS and D&M reports.

Summary of Pricing & Inflation Rate Assumptions

As of December 31, 2012Forecast Prices & Costs

Patos-Marinza Kuçova Currency Exchange Rates WTI @

Cushing, OK*

Brent @ Sollem Voe*

Inflation

Rate

WTI @ Cushing,

OK**

Brent @ Sollem Voe**

Inflation

Rate US$/ CDN$*

ALL/ EUR***

ALL/US$*** Year $/barrel $/barrel % /annum $/barrel $/barrel %

2013 93.30 108.00 2.0 93.00 111.00 2.0 1.00 - -

2014 92.10 102.03 2.0 94.35 108.35 2.0 1.00 - -

2015 89.70 98.20 2.0 95.72 105.72 2.0 1.00 - -

2016 87.50 94.80 2.0 101.88 107.88 2.0 1.00 - -

2017 92.01 97.42 2.0 106.62 106.62 2.0 1.00 - -

2018 93.85 99.37 2.0 109.30 107.10 2.0 1.00 - -

2019 95.72 101.35 2.0 112.62 110.36 2.0 1.00 - -

2020 97.64 103.38 2.0 114.87 112.57 2.0 1.00 - -

2021 99.59 105.45 2.0 117.17 114.82 2.0 1.00 - -

2022 101.58 107.56 2.0 119.51 117.12 2.0 1.00 - -

2023 103.61 109.71 2.0 121.90 119.46 2.0 1.00 - -

2024 105.69 111.90 2.0 124.34 121.85 2.0 1.00 - -

2025 107.80 114.14 2.0 1.00 - -

2026 109.96 116.42 2.0 1.00 - -

2027 112.16 118.75 2.0 1.00 - -

2028 114.40 121.13 2.0 1.00 - -

2029 116.69 123.55 2.0 1.00 - - 2030 119.02 126.02 2.0 1.00 - - 2031

121.40 128.54 2.0 1.00 - -

* RPS Price Forecast as at December 31, 2012

** D&M Price Forecast as at December 31, 2012; prices escalated @ 2% after 2024.

*** ALL = Albanian Leke 3.2 Weighted Average Historical Prices The following table summarizes the weighted average historical prices for the Patos-Marinza oilfield for the year ended December 31, 2012:

Weighted Average Historical Prices for the year ended December 31, 2012

First Quarter Second Quarter Third Quarter Fourth Quarter Year $/bbl $/bbl $/bbl $/bbl $/bbl Patos-Marinza 84.96 76.46 79.58 78.53 79.73

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PART 4: RECONCILIATIONS OF CHANGES IN RESERVES AND FUTURE NET REVENUE 4.1 Reserves Reconciliation A reconciliation of changes to the Company’s gross proved, gross probable and gross proved plus probable reserves is provided below. This reconciliation reflects changes to the Company’s reserves estimated using forecast prices and costs.

Reconciliation of Company Gross Reserves Forecast Prices & Costs

Heavy Oil

Patos-Marinza Kuçova Total Albania

Proved Probable P+P Proved Probable P+P Proved Probable P+P (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)

December 31, 2011 169,188 87,142 256,330 3,239 7,605 10,844 172,427 94,747 267,174 Extensions - - - 109 31 140 109 31 140 Improved Recovery 32,447 (679) 31,768 - - - 32,447 (679) 31,768 Technical Revisions (59,192) (8,272) (67,464) 25 870 895 (59,167) (7,402) (66,569)

Discoveries - - - - - - - - - Acquisitions - - - - - - - - - Dispositions - - - - - - - - -

Economic Factors (971) (418) (1,389) - - - (971) (418) (1,389) Production (5,497) - (5,497) (3) - (3) (5,500) - (5,500) Inventory Changes 71 - 71 - - - 71 - 71

December 31, 2012 136,046 77,772 213,819 3,370 8,506 11,876 139,416 86,278 225,695

* P+P stands for Proved Plus Probable For the purposes of this reconciliation, changes under “Acquisitions” include all forecast base production and adjustments from wells taken over during 2012 and wells anticipated to be taken over in future years. Changes under “Improved Recovery” include all incremental recovery gains associated with reactivating wells and infill drilling of new wells. Changes under “Technical Revisions” include all adjustments due to revisions in forecast parameters associated with all wells. Changes under “Economic Factors” result from changes in oil prices and all factors affecting changes in economic limit cut-offs.

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PART 5: ADDITIONAL INFORMATION RELATING TO RESERVES DATA 5.1 Undeveloped Reserves The Company’s undeveloped reserves exist in its Patos-Marinza and Kuçova oilfields, both of which are located in Albania. Most of these reserves are designated within the undeveloped category because relatively significant capital expenditures will be required in order to render these reserves capable of production. Plans for future development of these undeveloped reserves (based on Forecast Prices) are summarized below: Canadian Properties There are no reserves assigned to any Canadian properties. Albanian Properties Patos-Marinza

RPS assigns 107.6 MMbbls (Company 100% WI share) gross proved undeveloped and 60.3 MMbbls probable additional undeveloped reserves to the Patos-Marinza field, of which 26.9 MMbbl (proved) and 0.0 MMbbl (probable) were first attributed during 2012. These volumes are forecast to be recoverable from continued development of the field by taking over and reactivating heavy oil production wells throughout the reservoir and drilling horizontal wells as well as uphole recompletions. The Proved and Probable Undeveloped reserves are planned to be put on stream by a program of 209 attempted well reactivations, with an average success rate of 65%, resulting in 136 successful reactivations (includes those in the proved category). In addition, the program consists of 1,085 horizontal wells. For the first four years, this program includes successful well reactivations numbering 12 in 2013, 15 in 2014, 15 in 2015 and 20 in 2016. The horizontal well program is comprised of 98 wells in 2013, 106 wells in 2014, 106 wells in 2015 and 116 wells in 2016. The development programs are scheduled to maximize and maintain the capacity of production facilities for as long as is feasible. Forecasts of oil production rates and producing well counts for the development of proved and probable reserves are generated utilizing the outcomes of a probabilistic approach to reserves determination. Revised production forecasts are based on decline parameters from analysis of historical performance data from reactivated and recompleted existing wells applied at the P90 (proved) and P50 (proved and probable) probability levels and revised development schedules to fit capital allocation.

Successful recompletion well counts are derived by applying a chance of success to the total number of reactivation opportunities. The success rate for any given reactivation attempt is uncertain, therefore has been treated probabilistically. Historically, the average success rate is estimated at 65%, which is carried forward in future well reactivation development forecasts. Kuçova

Bankers Petroleum purchased 100% of the outstanding shares of Sherwood International Petroleum Ltd. in 2008, gaining operatorship of the Kuçova oilfield. The Kuçova oilfield is located in the South Central region of Albania, approximately 40 km north east of the Patos-Marinza oilfield. The Kuçova oilfield was discovered in 1928 and was developed with the drilling of 1,722 wells in 5 major pools (Kozare, Gege, Ferme, Arreza and Kucova Sector 1). As of December 31, 2012, approximately 459 wells were producing on primary production at approximately 230 bopd from the four main pools that Sherwood is planning development on (Kozare, Gege, Ferme, and Arreza). Engineering evaluation of the oilfield indicates it is severely pressure depleted with an estimated recovery factor of 9.8% to date with an ultimate recovery forecast of 10.9% on primary recovery.

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The petroleum-initially-in-place (PIIP) is currently estimated by D&M as 297 Mbbls of oil. The oil contained within Kuçova is characterized as heavy to medium crude oil in the 14 to 22 API range. The future redevelopment forecast for the field involves the implementation of secondary recovery schemes (waterflooding) to improve recovery from the field. All future reserves recovery assigned to Bankers, proved undeveloped and probable, is based upon the successful implementation of the secondary recovery projects. Production forecasts are based on analogous performance of similar type reservoirs under secondary recovery processes located in Western Canada. Initial field work was commenced in 2011 and production was commenced in 2012.

A summary of the aged undeveloped reserves is as follow:

Undeveloped Reserves Aged Summary Company Share Gross – As of December 31, 2012

Heavy Oil – Proved Undeveloped

Patos-Marinza Kucova Total Albania

First attributed Cumulative First attributed Cumulative First attributed Cumulative (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)

2010 50,870 117,531 - 3,239 50,870 120,770

2011 42,979 160,510 - 3,239 42,979 163,749

2012 26,891 187,402 109 3,354 27,000 190,756

Heavy Oil – Probable Undeveloped

Patos-Marinza Kucova Total Albania

First attributed Cumulative First attributed Cumulative First attributed Cumulative (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)

2010 27,087 135,447 - 8,177 27,087 143,624

2011 - 135,447 - 7,605 - 143,052

2012 - 135,447 31 8,502 31 143,949

5.2 Significant Factors or Uncertainties Estimates of economically recoverable oil and natural gas reserves (including natural gas liquids) and the future net cash flows there from are based upon a number of variable factors and assumptions, such as availability of capital to fund required infrastructure, commodity prices, production performance of recompleted wells and well recompletion success rates, successful drilling of infill wells, the assumed effects of regulation by government agencies and future operating costs. All of these estimates may vary from actual results. Estimates of the recoverable oil and natural gas reserves attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of future net revenues expected there from, may vary. The Company's actual production, revenues, taxes, development and operating expenditures with respect to its reserves may vary from such estimates, and such variances could be material. In addition to the foregoing, other significant factors or uncertainties that may affect either the Company’s reserves or the future net revenue associated with such reserves include:

Canada: Material changes to existing taxation or royalty rates and/or regulations, changes to environmental laws and regulations.

Albania: Political instability, potential and actual civil disturbances, restriction on repatriation of funds,

changes in laws affecting foreign ownership, existing contracts, environmental regulations, oil and gas prices, production regulations, royalty rates, income taxes, potential expropriation of property without fair compensation and restriction on exports.

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Information on other important economic factors or significant uncertainties that may affect components of the reserves data and other oil and gas information contained in this Form 51-101F1 are contained in the Company's Management’s Discussion and Analysis filed under the Company's profile at www.SEDAR.com and in the AIF under "Risk Factors".

5.3 Future Development Costs A summary of the estimated development costs deducted in the estimation of future net revenue attributable to various reserves categories and prepared under various price and cost assumptions are summarized in the following table. The Company expects to fund its estimated future development costs through some combination of internally generated cash flow, debt financing and equity issuance. There can be no guarantee that funds will be available or that the Board of Directors of the Company will allocate funding to develop all of the reserves requiring development in the RPS or D&M Reports. Failure to develop such reserves could negatively impact future net revenue.

Summary of Estimated Development Costs Attributed to Reserves Forecast Prices & Costs

Estimated Development Costs ($ millions)

Total Proved Total Proved + Probable Patos-Marinza

2013 212.6 201.8

2014 217.2 214.2

2015 239.3 236.0

2016 211.9 212.5

2017 217.1 221.9

Thereafter 1,014.1 989.3

Total 2,112.3 2,075.7

Kuçova

2013 6.4 6.1

2014 2.1 7.5

2015 2.1 14.4

2016 2.1 22.5

2017 - 23.6

Thereafter - 43.6

Total 12.6 117.7

Total Albania

2013 219.0 207.9

2014 219.3 221.7

2015 241.4 250.4

2016 214.0 235.0

2017 217.1 245.5

Thereafter 1,014.1 1,032.9

Total 2,124.9 2,193.4

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5.4 Disclosure of Resources

The following outlines the Contingent and Prospective resources attributed to the extension and increased development of the Patos-Marinza oilfield and Block “F” by RPS in the report prepared and issued with data as of December 31, 2012.

Bankers Albania holds a 100% interest in the Patos-Marinza licence and the Block “F” exploration Concession. The expected product type from these resources is heavy oil of similar characteristics to the oil present in the proven and probable Patos-Marinza reserves. For both the Contingent and Prospective Resources, RPS has utilized probabalistic methods to account for the risks and uncertainties associated with the resource volumes, and the P50 estimates presented herein are derived from the 50th percentile of the resulting probabalistic distributions. For the P50 volumes presented, there is an equal probability that actual volumes recovered will either be greater to or less than that volume.

With respect to Contingent resources, there is no certainty that it will be commercially viable to produce any portion of the resources. The factors which prevent resources being reclassified into reserves relate to the uncertainty of the success of primary and secondary recovery and thermal extraction techniques and the associated uncertainties in a development plan to recover the resources. The Company plans to continue the thermal pilot operations and drill additional core wells for assessing future thermal development plans in 2012. Economic production will most certainly necessitate access to natural gas feedstock to generate steam and the Company is actively involved in both exploration operations on Block “F” and discussions with third parties to procure access to gas.

With respect to Prospective resources, there is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. RPS requires further delineation by appraisal wells and mapping of this area to reclassify Prospective resources into Contingent resources. Disclosure of Contingent Resources: "Resources" are quantities of petroleum that are estimated to exist originally in naturally occurring accumulations, including the quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered.

"Contingent resources" are defined as those quantities of petroleum estimated, on a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as "contingent resources" the estimated discovered recoverable quantities associated with a project in the early project stage.

“Prospective resources” are those quantities of oil and gas estimated on a given date to be potentially recoverable from undiscovered accumulations. If discovered, they would be technically and economically viable to recover. Resources, contingent resources, and prospective resources do not constitute, and should not be confused with reserves.

Patos-Marinza and Block “F” Contingent and Prospective Resource Estimates (RPS)

As of December 31, 2012P50 Estimates

Patos-Marinza Resources Category (millions of barrels) Heavy Oil Contingent Resources 534 Prospective Resources 254

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PART 6: OTHER OIL AND GAS INFORMATION 6.1 Oil and Gas Properties and Wells The following discussion outlines the Company’s important properties, plants, facilities and installations: Canada

The Company has no oil and gas properties in Canada. Albania

Patos-Marinza

The Patos-Marinza heavy oilfield is located in southern Albania and was discovered in 1928. It is the largest onshore oilfield in continental Europe in terms of OOIP. Historically, Albpetrol was the sole operator of the field. The Company operates in the Patos-Marinza oilfield pursuant to a Petroleum Agreement with Albpetrol and a License Agreement with the Albanian State represented by the AKBN. The Company’s wholly owned subsidiary Bankers Albania entered into the Petroleum Agreement in June 2004, granting the Company the right to evaluate the potential for redevelopment of the Patos-Marinza oilfield for a period of 24 months and to subsequently propose a PoD. The Company started its operations by taking over 28 producing wells and 1 water disposal well in late July 2004. As of December 31, 2012, the Company had 1,416 wells in inventory, an increase of 120 wells compared to 1,296 at the end of 2011. All of the increased wells were drilled in 2012. Of the total 1,416 wells in inventory at year-end, 348 are active producing wells, 142 are non-producing wells, 16 are water disposal wells and 910 are non-active wells. Of the non-active wells, 576 wells shut-down with no current plans, 325 wells shut-in due to water intrusion problem, 2 exploration/appraisal wells, 1 thermal well and 6 lease use only wells. The Company’s PoD was initially approved by the AKBN in March 2006 and a subsequent revision to the PoD to include the infill horizontal and vertical drilling as part of the larger capital program was approved in June 2009 by the AKBN. With this approval, the Company is able to take-over the remaining wells in the field on a defined basis consistent with the PoD and produce and sell oil under the existing agreements for a period of 25 years with an option to extend at the Company’s election for further 5 year increments. The terms of the Petroleum Agreement include a 1% gross overriding royalty payable to Albpetrol which increases to 3% to 5% (based on an incremental sliding scale) after payout of funds expended by the Company. In addition, the Company pays a royalty to Albpetrol for the latter’s share of pre-existing or base production from the wells taken over by Bankers. This royalty is calculated on a per well basis using 70% of the average production for the preceding six months declining at 15% per annum. For the original 28 oil wells taken-over in July 2004, a fixed pre-existing production rate was applied and is declined at 10% per annum; 20 of the 28 wells have no pre-existing production liability as they were newly drilled wells by the previous operator, Anglo-Albanian Petroleum (AAP).

In 2008, a new royalty tax of 10% was implemented on sales volumes payable directly to the Government of Albania. The effective date of the new royalty tax is August 20, 2008, and is applied to gross sales amounts net of pre-existing production royalties in a fashion similar to the share of production royalty payable to Albpetrol. To mitigate the economic impact of the new royalty tax, as required by the Petroleum Agreement, the full royalty tax amount paid is added to the cost recovery balance to delay the profits tax horizon upon full cost recovery.

Bankers Albania sells crude oil produced from the Patos-Marinza oilfield through off-take agreements with both domestic and foreign parties. Domestically, Bankers Albania has agreements with the ARMO refineries. The price per barrel received by the Company under its agreement (subject to production quality) is determined by reference to the price of Brent crude oil. Bankers Albania has the right to export all of its production from the Patos-Marinza oilfield. The Company currently exports its crude oil production to a variety of refiners in the Mediterranean, Alma Petroli S.p.A and ENI

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S.p.A in Italy, Repsol S.A. in Spain, as well as three marketing companies, Mocoh S.A, Switzerland, Vitol S.A., Switzerland, and Trafigura PTE Ltd, Singapore. The export contracts’ pricing is based on market prices of Brent crude oil, and includes price limits for discussion and renegotiation purposes. During 2012, Bankers Albania exported 91% of its production, and received an overall average price of $79.73 per barrel. On average, the oil price received by the Company in 2012 represented approximately 71% of the Brent oil price. Kuçova

The Kuçova heavy oilfield is located in southern Albania and was discovered in 1928 with over 1,700 wells drilled into 5 oil pools, initially developed by Italian companies prior to WW II and by Albpetrol as sole operator of the field after 1945. Sherwood operates in the Kuçova oilfield pursuant to a Petroleum Agreement with Albpetrol under its existing license with the AKBN. Sherwood International Petroleum Ltd. is a wholly owned subsidiary of Bankers Petroleum Ltd. and entered into the Petroleum Agreement in September 2007, granting the Company the right to evaluate the potential for redevelopment of the Kuçova oilfield for a period of 24 months and subsequently propose a Plan of Development. The development and production phases for the Kuçova oilfield became effective in March 2011. To date, the Company has assumed 12 wells and has continued field operations and production in Kuçova. The main activity conducted by Sherwood during 2012 was the evaluation of the waterflood scheme in the Ferme pool. Well and production data has been gathered for 850 wells in 4 of the 5 oil pools, Arreza, Ferme, Gege and Kozare. Sherwood will takeover 122 wells for waterflood scheme in the Arreza pool, with 3 wells to be converted to injectors, 6 producers to be reactivated and 3 horizontal wells to be drilled (2 horizontals plus 1 verical core well that will be used to drill the 3rd horizontal well). Sherwood will have the same oil sales and marketing program as Bankers Albania and has the right to sell oil within Albania and it retains the right to export all of its production from the Kuçova oilfield and will likely conduct operations similar to the current practices as the Patos-Marinza operations. The Patos-Marinza license covers approximately 200 square kilometers, of which approximately 70 square kilometers represents the Plan of Development area and forms the basis for the reserves assessment. The Kuçova license covers approximately 54 square kilometers.

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Oil & Gas Wells Associated with Reserves As of December 31, 2012

Patos-Marinza Kuçova Total Albania

Active Suspended1

Service2 Gross Net Gross Net Gross Net Gross Net Gross Net

Producing 348 348 - - - - 2 2 350 350

Non-Producing 142 142 910 910 16 16 - 1,068 1,068

Total 490 490 910 910 16 16 2 2 1,418 1,418

(1) Suspended wells may be capable of production but which, for a variety of reasons, including, but not limited to, a lack of markets or development, are not placed on production at the present time.

(2) Service wells are used for the disposal or injection of water or other in-field service operations related to oil production

6.2 Properties with No Attributed Reserves The Company does not have any additional unproved properties, including those for which the Company expects its rights to explore, develop and exploit to expire within one year. 6.3 Forward Contracts As at December 31, 2012, the Company was not bound by any agreements which may impact the realization of future full market prices for its oil and gas production as described in this report. In August 2012, the Company entered into financial commodity put contracts representing 4,000 barrels of oil per day at a floor price of $80 per barrel for the period January 1, 2013 to December 31, 2013. The Company has no transportation obligations or commitments for future deliveries which exceed its expected related future production from proved reserves, as estimated using forecast prices and costs. 6.4 Additional Information Concerning Abandonment and Reclamation Costs The Company uses its internal historical costs to estimate its abandonment and reclamation costs. The costs are estimated on an area by area basis. In the absence of Company historical abandonment and reclamation costs, industry historical costs are used as required and where available. If representative comparisons are not readily available, an estimate is prepared based on the various regulatory abandonment requirements.

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Additional Information Concerning Abandoment & Reclamation Costs As of December 31, 2012 Forecast Prices & Costs

Total Net Wells Total Cost ($ millions) Proved Reserves Proved + Probable Reserves

Estimation Method Used

Proved Proved + Probable Undiscounted Disc. @ 10% Undiscounted Disc. @ 10%

Patos-Marinza

Standard engineering design cost estimating methodology, using historical cost databases

2,627 2,638 195 35 227 20

Total 2,627 2,638 195 35 227 20

Kuçova - - - - - - Total - - - - - -

Total Albania Total 2,627 2,638 195 35 227 20

6.5 Tax Horizon Canada: The Company currently has no revenue generating properties in Canada. Bankers has available for deduction against future Canadian taxable income, non-capital losses of approximately $51.2 million. These losses, if not utilized, will expire commencing in 2014. Albania: The Patos-Marinza concession is forecast to become taxable in 2015 and beyond under the forecast price scenario for proved reserves and in 2014 and beyond for the proved plus probable reserves scenario.

6.6 Costs Incurred For the year ended December 31, 2012, the Company incurred costs related to its acquisition, exploration and development activities as outlined in the following table.

Costs Incurred ($ thousands) Patos-Marinza Kuçova Total

Property Acquisition Costs: Proved Properties - 1,537 1,537 Unproved Properties/Wells - - -

Exploration Costs - - - Development Costs 221,126 - 221,126

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6.7 Exploration and Development Activities The Company’s drilling activity and results for the year ended December 31, 2012, are summarized in the following table. It should be noted that the data outlined in this table reflects those wells that the Company participated in and where the rig was released during the period.

Exploratory Wells Development Wells Gross Net Gross Net Albania

Oil Wells 1 1 127 127

Gas Wells Nil Nil Nil Nil

Service Wells Nil Nil Nil Nil

Suspended Wells Nil Nil Nil Nil

Abandoned Wells Nil Nil Nil Nil

Total Wells 1 1 127 127

The Company’s important exploration and development activities are summarized as follows: Canada

The Company did not engage in any exploration and development activity in Canada during 2012. Albania

Patos-Marinza

During 2012, the Company increased its total well inventory to 1,416 at the end of the year, mainly through drilling activities. At December 31, 2012, 348 wells were active oil producers with an additional 142 non-producing wells. Of the non-producing wells, 93 were waiting on service work and 49 wells were waiting to be reactivated. The remaining 926 wells were classified as “in-active” and are comprised of 16 wells used for water disposal, 576 wells shut-down with no current plans, 325 wells shut-in due to water intrusion problem, 2 exploration/appraisal wells, 1 thermal well and 6 lease use only wells. Reactivation activities include removal of Albpetrol surface equipment, surface lease remediation, construction of a new lease around the wellhead and road, removal of Albpetrol down-hole equipment, well clean-out, cement bond logging, and installation of a progressive cavity pumping system with associated surface drive equipment. In some wells, perforations are added to complete new intervals in the well and improve productivity. Also during 2012, the Company drilled 112 horizontal infill development wells, 7 lateral re-drills, 4 vertical delineation wells and 4 water disposal wells in Patos-Marinza field and 1 exploration well in Block “F”. The results of this further delineation of the horizontal drilling potential not only resulted in growing the reserve-linked resource, but also contributed to incremental reserves which partially offset negative technical revisions in reserves due to remapping of in place volumes. The approved Addendum to the Plan of Development outlines future development activities forecast by the Company to access additional reserves through the application of infill vertical and horizontal drilling, waterflood and thermal recovery techniques. The Addendum presented three scenarios to reflect volatility in the commodity markets. The development scenarios do not adhere strictly to the independent reserve scenarios provided by RPS, but the typical well parameters and expected ultimate recoveries per well type are consistent with statistical review of historical well performance and future forecast performance estimates.

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Kuçova

Sherwood International Petroleum Ltd, a wholly owned subsidiary of Banker Petroleum Ltd., was a signatory of the Production Sharing Agreement for the redevelopment of the Kuçova oilfield located in Albania dated September 4, 2007. The development and production phases for the Kuçova oilfield became effective in March 2011. To date, the Company has assumed 12 wells and has continued field operations and production in Kuçova. The main activity conducted by Sherwood during 2012 was the evaluation of the waterflood scheme in the Ferme pool. Well and production data has been gathered for 850 wells in 4 of the 5 oil pools, Arreza, Ferme, Gege and Kozare. Sherwood will takeover 122 wells for waterflood scheme in the Arreza pool, with 3 wells to be converted to injectors, 6 producers to be reactivated and 3 horizontal wells to be drilled (2 horizontals plus 1 verical core well that will be used to drill the 3rd horizontal well). 6.8 Production Estimates Estimated production volumes derived from the first year (2013) of the cash flow forecasts prepared in conjunction with the Company’s reserves data (and included in the RPS and D&M Reports) are provided in the following table.

Summary of Production Estimates

Proved Reserves Case For Year 2013

Estimated Production – 2013 (Gross) Patos-Marinza Kuçova Total Albania Reserve Category (Mbbl) (Mbbl) (Mbbl)

Heavy Oil 6,264 35 6.299

Summary of Production Estimates

Proved and Probable Reserves Case For Year 2013

Estimated Production – 2013 (Gross) Patos-Marinza Kuçova Total Albania Reserve Category (Mbbl) (Mbbl) (Mbbl)

Heavy Oil 6,446 34 6,480

(1) Significant fields represent greater than 20% of Company total (by country) of production in the first year of forecast

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6.9 Production History The Company’s historical production and netback data for period ended December 31, 2012 is presented below.

Summary of 2012 Company Share of Production & Netbacks

Heavy Oil Patos-Marinza Kuçova Q1 Q2 Q3 Q4 Total Year Total Year

Company share of daily production (bopd before deduction of royalties) 13,279 14,169 15,715 16,033 14,808 3

Average ($/bbl)

Price received 84.96 76.46 79.58 78.53 79.73 n/a

Royalties paid 15.85 13.35 16.09 12.70 14.46 n/a

Operating expenses 14.43 14.76 13.99 14.41 14.38 n/a

Sales and transportation 10.44 11.70 9.27 11.17 10.62 n/a

Netback 44.24 36.65 40.23 40.25 40.27 n/a

Total production (Mbbl before deduction of royalties) 1,284.9 1,288.6 1,436.7 1,487.0 5,497.2 2

Important fields (greater than 20% of total)

Patos-Marinza (represents 99% of above)

PART 7: NOTES The following definitions and guidelines are contained in Section 5.4 of Volume 1 of the Canadian Oil and Gas Evaluation Handbook (Second Edition, September 1, 2007) prepared jointly by The Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society) (the COGE Handbook) and have been prepared by the Standing Committee on Reserves Definitions of the CIM (Petroleum Society). Readers should consult the COGE Handbook for additional explanation and guidance. Certain other terms used in this Listing Application have the meanings assigned to them in NI 51-101 and accompanying Companion Policy 51-101 CP, adopted by the Canadian securities regulatory authorities.

Gross

(a) In relation to the Company's interest in production or reserves, its "company gross reserves", which are the Company's working interest (operating or non-operating) share before deduction of royalties and without including any royalty interest of the Company.

(b) In relation to wells, the total number of wells in which the Company has an interest.

(c) In relation to properties, the total area of properties in which the Company has an interest.

Net

(a) In relation to the Company's interest in production or reserves, the Company's working interest (operating and non-operating) share after deduction of royalty obligations, plus the Company's royalty interests in production or reserves.

(b) In relation to the Company's interest in a property, the total area in which the Company has an interest multiplied by the working interest owned by the Company.

The following definitions apply to both estimates of individual reserves entities and the aggregate of reserves for multiple entities:

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Reserve Categories

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations from a given date forward, based on:

Analysis of drilling, geological, geophysical and engineering data;

The use of established technology; and

Specified economic conditions

Reserves are classified according to the degree of certainty associated with the estimates:

(a) Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

(b) Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

Development and Production Status

Each of the reserve categories (proved and probable) may be divided into developed and undeveloped categories:

(a) Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.

(i) Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

(ii) Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

(b) Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.

In multi-well pools it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions above are applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

At least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and

At least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of

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reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

Forecast prices and costs

Future prices and costs that are:

(a) Generally accepted as being a reasonable outlook of the future; and

(b) If, and only to the extent that, there are fixed or presently determinable future prices or costs to which the Company is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a).

The forecast summary pricing table identifies benchmark reference pricing that apply to the Company.