Bankers Petroleum Announces 2011 Financial Results

33% increase in Production and doubles Cash Flow to $148 million

CALGARY, March 20, 2012 /CNW/ - Bankers Petroleum Ltd. ("Bankers" or the "Company") (TSX: BNK, AIM: BNK) is pleased to provide its 2011 Financial Results and Outlook for 2012.

In 2011, Bankers accomplished several key achievements including record production, reserves, net income and cash flow.  The Company also invested $243 million, making it the largest annual capital expenditure in Albania.

Highlights of the key achievements in 2011 include:

• Oil sales averaged 12,784 barrels of oil per day (bopd), an increase of 33% compared to 2010, as a result of the Company's ongoing horizontal drilling program and continuation of well reactivations.
  
  
• The original-oil-in-place (OOIP) resource assessment in Albania increased by 3% to 8.0 billion barrels from 7.8 billion barrels.  Reserves increased on a proved basis by 43% from 120.2 million barrels in 2010 to 172.4 million barrels in 2011 and by 12% on a proved plus probable basis from 237.6 million barrels in 2010 to 267.1 million barrels in 2011.  Additionally, the Company's independent reserves engineers assigned contingent and prospective resource oil estimates of 1.0 billion and 614 million barrels, respectively.  The corresponding net present value (NPV) after tax (discounted at 10%) of the proved plus probable reserves remained consistent at $2.0 billion from 2010 to 2011.
  
  
• Capital expenditures were $242.8 million, a 103% increase from 2010 of $119.7 million. During the year, Bankers contracted a fourth and fifth drilling rig. The Company drilled 84 wells during 2011, including 76 horizontal production wells, two vertical delineation wells, two cyclic steam horizontal wells and four water disposal wells. In 2010, a total of 55 wells were drilled.
  
  
• New export market agreements for 2012 have been completed representing an overall export average price of 72% of the Dated Brent oil benchmark.  ARMO, the Albanian refinery, also agreed to purchase Patos-Marinza crude in 2012 for an average price of 66% of Brent, which approximates the same netback value as the export market due to lower transport costs and having no port fees.  The 2012 pricing agreements represent an average 7% increase over the 2011 Patos-Marinza oil price.
  
  
• Construction of phase one of the crude oil sales pipeline, which connects the Patos-Marinza oilfield to the Fier Hub facility was completed.  Operations commenced in the first quarter of 2012. Social and environmental impact assessments for the second phase of the pipeline, from the Fier Hub to the export terminal at Vlore, are underway.
  
  
• With the ongoing reactivation and recompletion program expanding on the north side of the river, as well as the expected expansion of the drilling towards the north, the Company has constructed and completed a bridge crossing the Seman River to enable more efficient access for drilling and servicing equipment as well as fluid transportation.
  
  
• The Company has completed expansions of the central treatment facility (CTF) and increased the CTF capacity to 25,000 bopd.
  
  
• During 2011, Bankers continued with its environmental initiatives and completed the pilot remediation project in Sector 3. The project targeted the clean-up of old infrastructure and removal of legacy oil spills testing mechanical waste separation, thermal desorption, and bio-remediation technologies.  Larger scale clean-up processes are scheduled for implementation in 2012.
  
  
• Block "F" contains several seismically defined structural and stratigraphic amplitude anomalies prospective for oil and natural gas.  The first exploration location has been selected and land access is underway along with environmental permitting to commence surface lease construction.  The well is expected to be spud in April 2012.
  
  
• Bankers proceeded with the thermal pilot program during 2011, drilling two horizontal wells and a vertical well, along with installation of the steam generator.  Steam injection commenced in December, 2011.
  
  
• The Company continues to maintain a strong financial position at December 31, 2011 with cash of $54.0 million and working capital of $80.3 million.  Cash and working capital for December 31, 2010 was $108.1 million and $130.9 million, respectively.

Operational Update

First quarter 2012 year-to-date average production is 14,160 bopd. The Company has focused on expanding the water disposal capacity in the Patos-Marinza oilfield during the quarter with drilling of four water disposal wells.  Three of the four wells have finished drilling and surface facilities installation, and are being brought on injection; the fourth well will be brought on prior to the end of the quarter.  All four wells are expected to operate at full capacity in the second quarter and will enable the Company to gradually bring currently shut-in wells related to water disposal capacity, on production over the next few weeks.  Bankers intends to issue the first quarter 2012 operational update on April 10, 2012.

Outlook

The Company's capital program in 2012 will be $215 million, fully funded from projected cash flow based on an average $90 Brent oil price. The work program and budget includes the following:

• Drilling of 100 horizontal and vertical wells and completion of 60 well reactivations and workovers at the Patos-Marinza oilfield.
• Continuing the water disposal capacity expansion with additional water disposal drills and water control initiative with over 200 well isolations.
• Continuing the thermal pilot operations and drilling additional core wells for assessing future thermal development plans.
• Initiating social and environmental impact assessments, land permitting and material orders for the 35 kilometer second phase of the 70,000 bopd capacity pipeline from the Fier Hub to the Vlore export terminal with construction beginning in 2013.
• Expanding waterflood activities at the Kuçova oilfield with 5 injector conversions and 13 production reactivation wells.
• Drilling of 2 exploration wells on Block "F".
• Continuing with the environmental stewardship and social initiatives in our area of operations.

For additional information, please see a copy, with updated financial data only, of the Company's March corporate presentation on www.bankerspetroleum.com

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Caution Regarding Forward-looking Information

Information in this news release respecting matters such as the expected future production levels from wells, future prices and netback, work plans, anticipated total oil recovery of the Patos Marinza and Kuçova oilfields constitute forward-looking information. Statements containing forward-looking information express, as at the date of this news release, the Company's plans, estimates, forecasts, projections, expectations, or beliefs as to future events or results and are believed to be reasonable based on information currently available to the Company. 

Exploration for oil is a speculative business that involves a high degree of risk. The Company's expectations for its Albanian operations and plans are subject to a number of risks in addition to those inherent in oil production operations, including: that Brent oil prices could fall resulting in reduced returns and a change in the economics of the project; availability of financing; delays associated with equipment procurement, equipment failure and the lack of suitably qualified personnel; the inherent uncertainty in the estimation of reserves; exports from Albania being disrupted due to unplanned disruptions; and changes in the political or economic environment.

Production and netback forecasts are based on a number of assumptions including that the rate and cost of well takeovers, well reactivations and well recompletions of the past will continue and success rates will be similar to those rates experienced for previous well recompletions/reactivations/development; that further wells taken over and recompleted will produce at rates similar to the average rate of production achieved from wells recompletions/reactivations/development in the past; continued availability of the necessary equipment, personnel and financial resources to sustain the Company's planned work program; continued political and economic stability in Albania; approval of the Addendum to the Plan of Development;  the existence of reserves as expected; the continued release by Albpetrol of areas and wells pursuant to the Plan of Development and Addendum; the absence of unplanned disruptions; the ability of the Company to successfully drill new wells and bring production to market; and general risks inherent in oil and gas operations.

Contingent resources disclosed herein represent those quantities of petroleum estimated, as of 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. Prospective resources disclosed herein represent those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations, by application of future development projects.

Forward-looking statements and information are based on assumptions that financing, equipment and personnel will be available when required and on reasonable terms, none of which are assured and are subject to a number of other risks and uncertainties described under "Risk Factors" in the Company's Annual Information Form and Management's Discussion and Analysis, which are available on SEDAR under the Company's profile at www.sedar.com.

There can be no assurance that forward-looking statements will prove to be accurate. Actual results and future events could differ materially from those anticipated in such statements. Readers should not place undue reliance on forward-looking information and forward looking statements.

Review by Qualified Person

This release was reviewed by Suneel Gupta, Executive Vice President and COO of Bankers Petroleum Ltd., who is a "qualified person" under the rules and policies of AIM in his role with the Company and due to his training as a professional petroleum engineer (member of APEGGA) with over 20 years experience in domestic and international oil and gas operations.

About Bankers Petroleum Ltd.

Bankers Petroleum Ltd. is a Canadian-based oil and gas exploration and production company focused on developing large oil and gas reserves. In Albania, Bankers operates and has the full rights to develop the Patos-Marinza heavy oilfield and has a 100% interest in the Kuçova oilfield, and a 100% interest in Exploration Block F.  Bankers' shares are traded on the Toronto Stock Exchange and the AIM Market in London, England under the stock symbol BNK.

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following is management's discussion and analysis (MD&A) of Bankers Petroleum Ltd.'s (Bankers or the Company) operating and financial results for the year ended December 31, 2011, compared to the preceding year, as well as information and expectations concerning the Company's outlook based on currently available information. The MD&A should be read in conjunction with the audited consolidated financial statements for the years ended December 31, 2011 and 2010, together with the notes related thereto. Additional information relating to Bankers, including its Annual Information Form (AIF), is on SEDAR at www.sedar.com and on the Company's website at www.bankerspetroleum.com.

All dollar values are expressed in US dollars, unless otherwise indicated, and the financial results are prepared in accordance with International Financial Reporting Standards (IFRS).  The adoption of IFRS has not had an impact on the Company's operations or strategic decisions.  The Company reports its heavy oil production in barrels.

This MD&A is prepared as of March 16, 2012.

CHANGE IN ACCOUNTING POLICIES

On January 1, 2011, the Company adopted IFRS for financial reporting purposes, using a transition date of January 1, 2010.  The financial statements for the year ended December 31, 2011, including the required comparative information, have been prepared in accordance with IFRS 1 "First-Time Adoption of IFRS", as issued by the International Accounting Standards Board (IASB).  Previously, the Company prepared its annual consolidated financial statements in accordance with Canadian generally accepted accounting principles (GAAP).

Further information on the IFRS impacts is provided in the Critical Accounting Policies and Estimates section of this MD&A, including reconciliations between previous GAAP and IFRS financial position and comprehensive income.

Non-GAAP Measures

Certain measures in this document do not have any standardized meanings as prescribed by IFRS or previous GAAP and, therefore, are considered non-GAAP measures.  Netback per barrel and its components are calculated by dividing revenue, royalties, operating and sales and transportation expenses by the gross sales volume during the year. Netback per barrel is a non-GAAP measure and it is commonly used by oil and gas companies to illustrate the unit contribution of each barrel produced.

Net operating income is similarly a non-GAAP measure that represents revenue net of royalties, operating and sales and transportation expenses. The Company believes that net operating income is a useful supplemental measure to analyze operating performance and provides an indication of the results generated by the Company's principal business activities prior to the consideration of other income and expenses.

Adjusted earnings is similarly a non-GAAP measure that represents net income before gain (loss) on financial commodity contracts.

Funds generated from operations is also a non-GAAP measure and includes all cash from operating activities and are calculated before change in non-cash working capital.  Reconciliation to IFRS and GAAP measures is as follows:

CAUTION REGARDING FORWARD-LOOKING INFORMATION

This MD&A offers our assessment of the Company's future plans and operations as of March 16, 2012 and contains forward-looking information.  Such information is generally identified by the use of words such as "anticipate", "continue", "estimate", "expect", "may", "will", "project", "should", "believe" and similar expressions are intended to identify forward-looking statements.  Statements relating to "reserves" or "resources" are also forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the resources and reserves described can be profitably produced in the future.  All such statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements.  Management believes the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this MD&A should not be unduly relied upon.  These statements speak only as of the date hereof.

In particular, this MD&A contains forward-looking statements pertaining to the following:

• performance characteristics of the Company's oil and natural gas properties;
• crude oil production estimates and targets;
• the size of the oil and natural gas reserves;
• capital expenditure programs and estimates;
• projections of market prices and costs;
• supply and demand for oil and natural gas;
• expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; and
• treatment under governmental regulatory regimes and tax laws.

These forward-looking statements are based on a number of assumptions, including but not limited to:  those set out herein and in the Company's Form 51-101F1 Statement of Reserves Data and Other Oil and Gas Information (NI 51-101 Report), availability of funds for capital expenditures, a consistent success rate for well recompletions and drilling at Patos-Marinza oilfield, increasing production as contemplated by the Plan of Development (PoD), stable costs, availability of equipment and personnel when required, continuing favourable relations with Albanian governmental agencies and continuing strong demand for oil and natural gas.

Actual results could differ materially from those anticipated in these forward-looking statements as a result of the risks and uncertainties set forth below:

• volatility in market prices for oil and natural gas;
• risks inherent in oil and gas operations;
• uncertainties associated with estimating oil and natural gas reserves;
• competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel;
• the Company's ability to hold existing leases through drilling or lease extensions;
• incorrect assessments of the value of acquisitions;
• geological, technical, drilling and processing problems;
• fluctuations in foreign exchange or interest rates and stock market volatility;
• rising costs of labour and equipment;
• changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry.

The Company, from time to time, updates its forward-looking information based on the events and circumstances that occurred during the period and has adjusted its capital expenditure program accordingly to ensure that capital expenditures are funded by cash provided by operations, cash on hand and its available credit.

Readers are cautioned that the foregoing lists of factors are not exhaustive.  The forward-looking statements contained in this MD&A are expressly qualified by this cautionary statement.

BUSINESS PROFILE

Bankers is a Canadian-based oil exploration and production company focused on maximizing the value of its heavy oil assets in Albania. The Company is targeting growth in production and reserves through application of new and proven technologies by an experienced technical team. The Company generates all of the oil revenue from its operations in Albania, which is located northwest of Greece in South Eastern Europe.

In Albania, Bankers operates and has the full rights to develop the Patos-Marinza and Kuçova oilfields pursuant to License Agreements with the Albanian National Agency for Natural Resources (AKBN) and Petroleum Agreements with Albpetrol Sh.A (Albpetrol), the state owned oil and gas corporation. The development and production phases became effective in March 2006 and March 2011, respectively, each having a 25 year term with an option to extend at the Company's election for further five year increments. The Patos-Marinza oilfield is the largest onshore oilfield in continental Europe, holding approximately 7.7 billion barrels of original-oil-in-place (OOIP).  The Company also has exclusive rights to exploration Block "F" (adjacent to the Patos-Marinza oilfield), a 185,000 acre oil and gas prone exploration field.

Bankers increased its oil revenue, net operating income and funds generated from operations during the year through its continued success with the horizontal drilling program and ongoing well reactivations.  The average oil sales price received by the Company during the year was $72.84/bbl, a 50% increase from $48.64/bbl in 2010.   The higher average oil price during 2011 resulted in a 57% increase in the average netback from $23.15/bbl in 2010 to $36.36/bbl in 2011. On average, the oil price received by the Company in 2011 represented approximately 65% of the Brent oil price, an improvement from 61% of Brent in 2010.   Oil exports represented 80% of the total revenue during the year, compared to 85% in 2010, with the balance supplying the domestic Albanian refineries.

In 2011, capital expenditures were $242.8 million compared to $119.7 million in 2010 and $38.3 million in 2009, an increase of 103% and 533% respectively.

Shareholders' equity increased to $412.7 million in 2011 from $346.3 million in 2010 and $214.8 million in 2009. The increase in shareholders' equity in 2011 was mainly due to higher net income during the year of $36.0 million.

Highlights

Bankers accomplished several key achievements during 2011:

• Oil sales averaged 12,784 barrels of oil per day (bopd), an increase of 33% compared to 2010 as a result of the Company's ongoing horizontal drilling program and continuation of well reactivations.
  
  
• The OOIP resource assessment in Albania increased by 3% to 8.0 billion barrels from 7.8 billion barrels.  Reserves increased on a proved basis by 43% from 120.2 million barrels in 2010 to 172.4 million barrels in 2011 and by 12% on a proved plus probable basis from 237.6 million barrels in 2010 to 267.1 million barrels in 2011. Additionally, the Company's independent reserves engineers assigned contingent and prospective resource oil estimates of 1.0 billion and 614 million barrels, respectively.  The corresponding net present value (NPV) after tax (discounted at 10%) of the proved plus probable reserves remained consistent at $2.0 billion from 2010 to 2011.
  
  
• Capital expenditures were $242.8 million, a 103% increase from 2010 of $119.7 million. During the year, Bankers contracted a fourth and fifth drilling rig.  The Company drilled 84 wells during 2011, including 76 horizontal production wells, two vertical delineation wells, two cyclic steam horizontal wells and four water disposal wells. In 2010, a total of 55 wells were drilled.
  
  
• New export market agreements for 2012 have been completed representing an overall export average price of 72% of the Dated Brent oil benchmark.  ARMO, the Albanian refinery, also agreed to purchase Patos-Marinza crude in 2012 for an average price of 66% of Brent, which approximates the same netback value as the export market due to lower transport costs and having no port fees.  The 2012 pricing agreements represent an average 7% increase over the 2011 Patos-Marinza oil price.
  
  
• Construction of phase one of the crude oil sales pipeline, which connects the Patos-Marinza oilfield to the Fier Hub facility was completed.  Operations commenced in the first quarter of 2012. Social and environmental impact assessments for the second phase of the pipeline, from the Fier Hub to the export terminal at Vlore, are underway.
  
  
• With the ongoing reactivation and recompletion program expanding on the north side of the river, as well as the expected expansion of the drilling towards the north, the Company has constructed and completed a bridge crossing the Seman River to enable more efficient access for drilling and servicing equipment as well as fluid transportation.
  
  
• The Company has completed expansions of the central treatment facility (CTF) and increased the CTF capacity to 25,000 bopd.
  
  
• During 2011, Bankers continued with its environmental initiatives and completed the pilot remediation project in Sector 3.  The project targeted the clean-up of old infrastructure and removal of legacy oil spills testing mechanical waste separation, thermal desorption, and bio-remediation technologies.  Larger scale clean-up processes are scheduled for implementation in 2012.
  
  
• Water injection commenced in Kuçova during 2011 with one injector and two producers.  The Company intends to expand the waterflood project in 2012.
  
  
• Bankers proceeded with the thermal pilot program during 2011, drilling two horizontal wells and a vertical well, along with installation of the steam generator.  Steam injection commenced in December 2011.
  
  
• In February 2011, the Company entered into financial commodity put contracts representing 4,000 bopd at a floor price of $80/bbl for the period January 1, 2012 to December 31, 2012.
  
  
• Block "F" contains several seismically defined structural and amplitude anomalies prospective for oil and natural gas.  The first Block "F" exploration location has been selected and land access is underway along with environmental permitting to commence surface lease construction.  The first well is expected to be spud in the first quarter of 2012. During the year, the Company provided a $5.0 million bank guarantee for certain capital projects in Block "F".
  
  
• The Company continues to maintain a strong financial position at December 31, 2011 with cash of $54.0 million and working capital of $80.3 million.  Cash and working capital for December 31, 2010 was $108.1 million and $130.9 million, respectively.

GROWTH STRATEGY

Bankers' strategy is focused on petroleum assets that have long-life reserves with production growth potential. Employing its knowledge base and technical expertise, the Company is working to optimize its existing assets from the application of primary, secondary and enhanced oil recovery (EOR) extraction technologies, creating long-term value for shareholders. This will be accomplished through the attainment of its main objectives:  increasing production, reserves, funds generated from operations and net asset value.

Bankers' strategic priorities are to:

• Increase reserves and production;
• Maintain a strong balance sheet by controlling debt and managing capital expenditures;
• Control costs through efficient management of operations;
• Pursue new and proven technology applications to improve operations and assist exploration endeavours;
• Expand infrastructure (pipelines, storage, treating capacity) to increase production capacity in a cost-effective manner;
• Explore undeveloped acreage to identify and create development opportunities;
• Maintain a strong focus on employee, contractor and community health and safety; and
• Manage environmental and social performance to minimize negative ecological impacts and ensure continued stakeholder support.

In pursuing the long-term growth strategy, Bankers is primarily focused on accessing the heavy oil upside from its Albanian assets, which includes the effective implementation of the Patos-Marinza development plan as well as applying EOR and secondary extraction techniques to increase the field's recoverable reserves.

In addition, the Company's strategy involves identifying and acquiring other potential petroleum opportunities in Albania to increase overall value. The area contains several seismically defined structures and amplitude anomalies prospective for oil and natural gas.

Throughout the year, Bankers focused on achieving its priorities and implementing its capital programs in Albania.  The Company funded its capital programs using funds generated from operations and existing cash.  Strategic allocation of the work program and budget is designated to provide additional recoverable reserves at the Patos-Marinza and Kuçova oilfields and still achieve an appropriate growth in production.

Key Performance Indicators

Key performance indicators relate to those factors that Bankers can directly affect, and are indicators of the Company's ability to provide long-term value to its shareholders, which include optimizing the cost of operations over time, improving exploration and development and increasing operational performance through technology and best practices. Key measurements include operating costs, production volumes and safety performance. These key performance indicators are continuously reviewed and monitored.

In addition, strengthening relationships with employees, governments, communities and other stakeholders are important aspects of the business for Bankers. The effective management of these relationships allows the Company to tap into new growth opportunities and efficiently develop operations for the future.

CAPABILITY TO DELIVER RESULTS

Activity in the oil industry is subject to a range of external factors that are difficult to actively manage, including commodity prices, resource demand, regulator and environmental regulations and climate conditions. Bankers gives significant consideration to these factors and backs-up its strategy by employing and positioning necessary resources to deliver on its goals and commitment to increase value for shareholders.  The Company focuses its capital on opportunities that provide the potential for the best returns. Comprehensive insurance policies are in place to help safeguard its assets, operations and employees.  Relationships with stakeholders and key partners are carefully cultivated to assist in the Company's future development and growth. The experiences of management and its technical team ensure that the Company can fulfill its commitment to deliver maximum value to its shareholders.

INDUSTRY & ECONOMIC FACTORS

World crude oil demand strengthened during the course of 2011 and the average Brent oil price improved by 40% from $79.50/bbl in the previous year to $111.26/bbl in 2011.

In 2011, 80% of the Company's crude oil sales went to international markets.  The remainder was sold to ARMO, an independent petroleum refinery in Albania.  Both the domestic and international sales prices are based on the Dated Brent oil price benchmark.

On February 28, 2011, the Company entered into financial commodity put contracts representing 4,000 bopd at a floor price of $80/bbl for the period January 1, 2012 to December 31, 2012.

On an average basis, the Canadian dollar strengthened by 4% in 2011. The fluctuations in the foreign exchange currencies impacted cash and some short-term investments that are denominated in Canadian dollars.

Significant Developments in 2011

Bankers accomplished several key achievements in 2011 in response to improvements in the commodity market.  These events included expansion of the horizontal drilling program by activating a fourth and fifth drilling rig; construction of the first phase of the crude oil sales pipeline; construction of the Seman River bridge; construction of the third and fourth oil treating trains at the central treating facilities; continued environmental initiatives including completion of pilot area legacy pollution clean-up and technology trials; commencement of thermal operations at the southern Patos Cyclic Steam Pilot; commencement of water injection and production in Kuçova and the overall growth of capital programs.

The Company drilled 84 wells during 2011, including 76 horizontal production wells, two vertical delineation wells, two cyclic steam horizontal wells and four water disposal wells.

The Company provided a $5.0 million bank guarantee for certain capital projects in Block "F". The first Block "F" exploration location has been selected and surface lease construction is underway with expected spud of the well in April 2012.

QUARTERLY SUMMARY

^{(1) Represents net income before gain (loss) on financial commodity contracts.}

DISCUSSION OF OPERATING RESULTS

Sales, Revenue and Netback

Average sales for 2011 were 12,784 bopd, an increase of 33% from 9,597 bopd for 2010.  The increase in sales was due to expansion of the drilling program, continued well reactivation program and well recompletion program focused on bringing high productivity wells on stream.

At the end of December 2011, the Company had approximately 280 active producing wells as compared to 250 wells at the end of 2010.  This does not include all the productive wells as several are down at any point in time for normal operational servicing, such as pump changes, cleanouts, and stimulation.  In addition, several infrastructure projects were being completed at the end of the year limiting the maximum active well count. The Company total well inventory including wells taken-over from Albpetrol as well as new drills increased from 826 at the end of 2010 to 1,296 at December 31, 2011.  The majority of the additional wells were taken over in the northern region of the field to access areas north of the river and to consolidate our operational areas rather than for production purposes.

The Company received an average $72.84/bbl (65% of Brent) for the year, an increase of 50% from $48.64/bbl (61% of Brent) for the preceding year.  This increase was largely due to the increase in commodity prices during 2011.  The average Brent oil price for 2011 was $111.26/bbl, a 40% improvement as compared to $79.50/bbl in 2010. Oil revenue increased by 100% to $339.9 million in 2011 compared to $170.4 million in 2010 due to higher realized oil prices and increased sales.

The Company's sales averaged 13,399 bopd during the fourth quarter of 2011 compared to 13,667 bopd during the preceding quarter and 10,424 bopd during the fourth quarter of 2010. The December 31, 2011 crude oil inventory level increased during the fourth quarter by 40,000 barrels to 241,000 barrels, as a result of storage requirements associated with additional tanks. Fourth quarter sales were slightly lower than the previous quarter due to limitations on water disposal capability.  The Company's produced water handling capacity is expected to increase in the second quarter of 2012 as a result of four new water disposal wells drilled in the first quarter of 2012. Total revenues for the fourth quarter of 2011 was $88.3 million compared to $93.7 million in the third quarter of 2011 and $50.9 million during the same period in 2010.  Bankers received an average sales price of $71.67/bbl during the fourth quarter of 2011 compared to $74.48/bbl during the preceding quarter and $53.12/bbl during the same period in 2010. The Company exported 93% of its crude oil during the fourth quarter of 2011 compared to 80% during the preceding quarter and the same period in 2010.

The netback during the fourth quarter of 2011 was $30.56/bbl (43% of the average price) compared to $35.71/bbl (48% of the average price) for the preceding quarter and $26.55/bbl (50% of the average price) for the fourth quarter of 2010.

Royalties

Royalties in Albania are calculated pursuant to the Petroleum Agreement with Albpetrol and consist of a royalty based on Albpetrol's pre-existing production (PEP), a 1% gross overriding royalty (ORR) on new production and a 10% royalty tax (RT) on net production. Overall royalties for the year represented 19% of oil revenue, slightly reduced from 20% for 2010. As a percent of revenue, the various royalty components currently represent 8% from PEP, 1% for the ORR and 10% for the RT.   Fluctuations in royalty on a per barrel basis are mainly due to changes in the underlying oil prices.

In the fourth quarter of 2011, royalties were $15.14/bbl (21% of revenue) compared to $14.68/bbl (20% of revenue) during the preceding quarter and $10.26/bbl (19% of revenue) for the same period in 2010.

Operating Expenses

Operating expenses for the year increased by 24% from $10.49/bbl in 2010 to $13.04/bbl in 2011.  On a percentage of revenue basis, operating costs represented 18% of the revenue for the year, compared to 22% for the preceding year.  The improvement from 2010, as a percentage of revenue, was due to increased sales levels and the significant increase in commodity prices.  On a per active well basis, the energy costs were higher as a result of increased diesel, propane, and electricity costs as well as higher well servicing and down-hole equipment costs with a greater frequency of well interventions required for pump changes, clean outs, and stimulation. The personnel costs also increased with the addition of operations staff for the higher pace of development and larger number of active wells operating. Of the total operating expenses incurred during 2011, $5.11/bbl (39%) related to fixed costs and $7.93/bbl (61%) related to variable costs, consistent with 40% and 60% for 2010.

Operating expenses during the fourth quarter of 2011 were $14.04/bbl (20% of revenue) compared to $13.78/bbl (19% of revenue) during the third quarter and $10.98/bbl (21% of revenue) during the same period in 2010. The moderate increase in operating expenses, as a percentage of revenue, compared to the preceding quarter was a result of increased well servicing costs during the fourth quarter. The decrease from the fourth quarter of 2010 as a percentage of revenue was due to the higher sales volumes and commodity prices, while the per well costs in the fourth quarter of 2011 were higher than the same quarter in 2010 with the higher frequency of well servicing associated with normal optimization of the wells.

Sales and Transportation

Sales and transportation (S&T) costs were $9.74/bbl during 2011, an increase from $5.38/bbl in the previous year mainly due to the increase in blending costs driven by higher diluent consumption and pricing.

S&T expenses during the fourth quarter were $11.93/bbl compared to $10.31/bbl during the preceding quarter and $5.33/bbl in the fourth quarter of 2010.  The increase in S&T costs compared to the previous quarter and same period in 2010 was mainly due to the increased blend ratio of diluent in the sales oil and the higher export sales.   The export sales were 93% of total sales for the fourth quarter, 80% for both the preceding quarter and for the same period in 2010. Blending costs were $7.97/bbl for the fourth quarter of 2011, compared to $7.32/bbl for the third quarter of 2011, and $2.80/bbl for the same period in 2010.  The additional diluent was required to improve the treating and mobility of the sales oil with the development of heavier oil from the wells drilled during the year. Trucking costs were $2.13/bbl in the fourth quarter of 2011, compared to $1.98/bbl in the third quarter of 2011 and $1.93/bbl in the fourth quarter of 2010.  Port fees for the fourth quarter of 2011 were $1.83/bbl, an increase from $1.01/bbl in the preceding quarter and $0.60/bbl for the same period in 2010.

General and Administrative Expenses

General and administrative expenses (G&A) for the year were $13.8 million ($2.95/bbl), compared to $10.6 million ($3.01/bbl) in 2010. The increase in G&A from 2010 was mainly due to additional personnel, increases in professional fees and the strong Canadian dollar versus US dollar.

During the year, the Company capitalized $14.8 million of G&A and share-based payments compared to $7.8 million for the preceding year. These expenses were directly related to acquisition, exploration and development activities in Albania.

Non-cash share-based payments pertaining to stock options granted to officers, directors, employees and service providers were $24.5 million (2010 - $14.5 million).  Of this amount, $11.0 million (2010 - $7.9 million) was charged to earnings and $13.5 million (2010 - $6.6 million) was capitalized.

G&A expenses for the fourth quarter of 2011 were $3.8 million compared to $3.5 million in the preceding quarter and $3.3 million for the same period in 2010.  The increase from the fourth quarter of 2010 was mainly due to additional personnel costs and professional fees.

Depletion and Depreciation

Depletion and depreciation (D&D) expenses for the year were $40.4 million ($8.47/bbl) compared to $22.5 million ($6.29/bbl) for 2010.  D&D expenses correspond to the respective production levels and the impact of capital expenditures relative to the depletable basis.  The increase in D&D expenses reflects higher production in Albania and an increase in depletable assets, inclusive of higher future capital requirements. The Company's independent reserve evaluation, prepared in accordance with the National Instrument NI 51-101, assessed proved and probable gross reserves of 267.1 million barrels at December 31, 2011, an increase of 12% from 237.6 million barrels at December 31, 2010.

D&D costs for the quarter ended December 31, 2011 were $13.4 million ($10.50/bbl), compared to $9.6 million ($7.88/bbl) for the preceding quarter and $7.5 million ($7.56/bbl) for the same period in 2010.  The increase in D&D reflects the higher depletion base as a result of increased future development costs combined with the increase in production during the quarter.  The depletable base at December 31, 2011 includes a provision of $1.9 billion for expected future capital programs, compared to $1.0 billion at September 30, 2011 and $1.2 billion at December 31, 2010.  D&D represented 12% of total revenue for the year ended December 31, 2011, slightly lower than 13% for 2010.  The reduction, as a percentage of revenue, was mainly due to the increase in reserve base, increase in production and commodity price.

Income Taxes

As of December 31, 2011, the Company recorded a $123.0 million deferred income tax liability, compared to $63.6 million at the end of 2010, in relation to the Company's Albanian assets and liabilities. Deferred income tax expense for 2011 was $59.3 million compared to $24.7 million for the preceding year.  The increase in deferred income taxes from 2010 was mainly due to the increase in net income incurred in 2011 and non-deductible costs, including share-based payments of the Albanian segment. For 2011, deferred income tax expense was 62% of income before income tax compared to 70% for 2010. This reduction was mainly due to higher income of the Albanian segment.

On a quarterly basis, the Company recorded deferred income tax expense of $10.6 million compared to $20.4 million for the preceding quarter and $7.3 million for the same period in 2010. The change in the deferred income tax expense was mainly due to the fluctuations in net income of the Albanian segment.

At December 31, 2011, $235.2 million remains to be recovered in the cost recovery pool representing Bankers cumulative capital investment in Albania of approximately $577.4 million, as compared to $152.6 million in the cost recovery pool at December 31, 2010.

The cost recovery pool represents deductions for income tax purposes in Albania at a 50% income tax rate.  Bankers is presently not required to pay cash taxes in any jurisdiction.  In Canada, the benefit of non-capital losses of approximately $33.8 million as of December 31, 2011 has not been recognized in the financial statements.

Net Income and Funds Generated from Operations

The Company recorded net income of $36.0 million ($0.146 per share) during the year ended December 31, 2011 and $10.5 million ($0.044 per share) for the year ended December 31, 2010.

The Company realized net income of $0.3 million for the fourth quarter of 2011 compared to $13.7 million in the preceding quarter and $4.6 million for the same period in 2010.  The reduction of net income for the fourth quarter of 2011 was primarily due to an unrealized loss of $5.9 million on financial commodity contracts compared to an unrealized gain of $5.0 million in the preceding quarter, along with higher depletion charges associated with increased future development costs.

Funds generated from operations were $147.9 million for the year ended December 31, 2011, an increase of 109% compared to $70.9 million in 2010.  The increase in funds generated from operations was mainly due to higher sales and commodity prices during the year.

Funds generated from operations were $32.7 million for the fourth quarter of 2011 compared to $42.1 million in the previous quarter and $23.3 million for the same period in 2010.

OIL RESERVES

Annually, the Company obtains independent reserves evaluations of its Albanian properties by RPS Energy Canada Ltd. (Patos-Marinza oilfield) and by DeGolyer and MacNaughton Canada Ltd. (Kuçova oilfield).  At December 31, 2011, reserves increased on a total proved (1P) and total proved plus probable (2P) basis and remained consistent on a total proved, probable and possible (3P) basis.  Changes within each reserve basis are shown below.  The 2011 finding and development costs for the Albanian properties represented $11.50/bbl on a 1P basis, $8.48/bbl on a 2P basis and $6.18/bbl on a 3P basis.

Gross Oil Reserves- Using Forecast Prices (MMbbls)

Net Present Value at 10% - After Tax Using Forecast Prices ($millions)

In the Patos-Marinza oilfield, the OOIP at the end of 2011 increased 3% to 7.7 billion barrels from 7.5 billion at the end of 2010.  Additionally, the Company's independent reserves engineers assigned contingent and prospective resource oil estimates of 1.0 billion and 614 million barrels, respectively.  This assessment is based on primary horizontal and secondary water-flood developments as well as thermal development technologies being applied to areas of the Patos-Marinza field.

The reserves growth in the Patos-Marinza field is primarily attributable to continued implementation of horizontal drilling, expansion of field development to enhance recovery and the upgrade of 3P into 2P reserves and 2P into 1P reserves, based on extended periods of actual well and reservoir performance. Significant additional reserves resulted from horizontal drilling in new areas of the field where no reserves had been booked in previous years, which resulted in a direct migration of contingent resource into proved and possible reserves. All of Patos-Marinza's 2011 reserves estimates are from primary recovery methods.

The Company acquired the Kuçova asset in 2008 and the OOIP resource estimate is 297 million barrels.  This property is currently in early stage development with no Company production from the Kuçova oilfield in 2011.  The water-flood pilot started in 2011 with one injector and two producers with plans to expand the program in 2012.  Bankers expects to continue activity in this area in 2012 utilizing a variety of extraction techniques that will lead to creation of a development plan.

The Company acquired the Block "F" asset in 2010.  There are currently no oil or gas resource bookings for Block "F" in 2011.  A thorough review of the available seismic lines including reprocessing of the lines was conducted in 2011 and exploration prospect drilling on structural and stratigraphic anomalies is planned for 2012.

Capital expenditures for the year were $242.8 million, compared to $119.7 million in the preceding year, an increase of 103%. This increase was mainly due to the expansion of the Company's capital programs in drilling, reactivation, thermal project and other base projects, including the sales pipeline construction, facility infrastructure expansion and environmental stewardship programs in the Patos-Marinza oilfield.  During the year, Bankers spent $110.2 million on the drilling program, which consisted of 76 horizontal production wells and 2 vertical delineation wells, compared to $69.6 million in 2010 (50 horizontal wells and 2 vertical wells).  Bankers spent $25.6 million on well reactivations compared to $8.4 million in the previous year.  The increase in well-reactivation costs was a result of additional wells attempted for reactivation during the year compared to the previous year.  A total of 384 wells were taken over from Albpetrol in 2011, compared to 199 in 2010.  These wells are primarily for contiguous area consolidation purposes, but several wells were also available for production reactivation.

During 2011, Bankers invested $11.8 million on the thermal project compared to $327,000 in the previous year.  Two cyclic steam horizontal wells were drilled during the year and thermal operations commenced at the southern Patos Cyclic Steam Pilot in late 2011. Base program expenditures increased 197% during the year due to the increase in facility infrastructure, environmental stewardship, pipeline and sale infrastructure and water control/disposal initiatives (four water disposal wells were drilled during the year).

Included in property, plant and equipment as of December 31, 2011 are oilfield equipment of $37.7 million for utilization in future drilling, reactivation and infrastructure programs in the Patos-Marinza oilfield, as compared to $17.5 million at December 31, 2010.

During the fourth quarter of 2011, Bankers incurred $56.3 million in capital expenditures; $36.8 million on drilling operations, $3.7 million on well reactivations and $15.6 million related to the base program. The balance of the expenditures was incurred on the work-over program, thermal project and other miscellaneous expenses and capitalized G&A. By comparison, in the fourth quarter of 2010, the Company incurred $37.4 million in capital expenditures; $23.4 million on drilling operations, $3.1 million on well reactivations and $5.9 million on the base program, with the balance of the expenditures incurred on the evaluation area and other miscellaneous expenses and capitalized G&A.

LIQUIDITY AND CAPITAL RESOURCES

At December 31, 2011, Bankers had working capital of $80.3 million (including cash and cash equivalents totalling $54.0 million) and long-term bank loans of $57.2 million.  At December 31, 2010, the Company had working capital of $130.9 million and long-term bank loans of $21.8 million.

Bankers has credit facilities totalling $132.1 million, of which $70.4 million was utilized at December 31, 2011.  The majority of the credit facilities represent a reserve-based long-term financing of $110.0 million from the International Finance Corporation and European Bank for Reconstruction and Development, of which $56.0 million was drawn. The $22.1 million Raiffeisen facility includes a revolving operating loan of $20.0 million and term loan of $2.1 million, of which $14.4 million was drawn. Repayment of $4.0 million was made on the term loans during the year.

The Company's approach to managing liquidity is to ensure a balance between capital expenditure requirements and funds generated from operations, available credit facilities and working capital.

There were approximately 247.7 million shares outstanding as at December 31, 2011 and 252.9 million shares outstanding as at March 16, 2012. In addition, the Company had approximately 20.3 million stock options and approximately 4.7 million outstanding warrants at December 31, 2011.  Subsequent to 2011 year-end, approximately 3.8 million stock options were granted, approximately 0.5 million stock options were exercised and approximately 4.7 million warrants were exercised, generating proceeds of approximately $1.0 million and $11.1 million, respectively. All remaining warrants expired on March 1, 2012.  On March 16, 2012, Bankers has approximately 24 million stock options and nil warrants outstanding.

Directors and officers of the Company represent approximately 7 percent ownership in the Company, on a fully diluted basis, as of December 31, 2011 and approximately 8 percent as of March 16, 2012. The strong ownership position of the directors and officers creates an alignment with shareholders and a team that is dedicated to activities that support future value creation.

Financial Commodity Contracts

Bankers' financial results are influenced by fluctuations in commodity prices, which include price differentials.  As a means of managing this commodity price volatility and its impact on cash flows, the Company entered into various financial hedging agreements during the first quarter of 2011.  The Company purchased put contracts representing 4,000 bopd at $80/bbl of Dated Brent for 2012, for $6.6 million.  Unsettled derivative financial contracts are recorded at the date of the financial statements based on the fair value of the contracts.  Changes in fair value result from volatility in forward curves of commodity prices and changes in the balance of unsettled contracts between periods.  The fluctuations in fair values are recognized as unrealized gain and loss on financial commodity contracts. As of December 31, 2011, the fair value of these contracts was $3.7 million.

Plan of Development

Bankers has no capital expenditure commitment for the Patos-Marinza oilfield under the Petroleum Agreement.  Bankers annually submits a work program to AKBN which includes the nature and the amount of capital expenditures to be incurred during that year. Significant deviations in this annual program from the Plan of Development will be subject to AKBN approval. The Petroleum Agreement provides that disagreements between the parties will be referred to an independent expert whose decision will be binding. The Company has the right to relinquish a portion or all of the contract area. If only a portion of the contract area is relinquished then the Company will continue to conduct petroleum operations on the portion it retains and the future capital expenditures will be adjusted accordingly.

Commitments

The Company has long-term lease commitments for office premises in Canada and Albania.  The minimum lease payments are as follows:

The Company has an operating loan, revolving loan and two term loans outstanding with three international banks, totalling $70.4 million.   The operating loan matures on March 31, 2012 and subsequent to December 31, 2011, the operating loan has been approved for renewal for an additional two years. The revolving loan declines to $16.5 million on October 15, 2013, $8.3 million on October 14, 2014 with final repayment due on October 15, 2015.  The 2009 term loan is repayable in equal monthly instalments of $74,100 ending on April 30, 2014 and the environmental term loan is repayable commencing April 2013 in bi-annual instalments pro-rata to the amounts drawn. Of the amount outstanding, $13.2 million is classified as current and $57.2 million as long-term.  Principal repayments of these loans are as follows:

Quarterly Variability

Fluctuations in quarterly results are due to a number of factors, some of which are not within the Company's control such as seasonality and commodity prices.

• Seasonality of winter operating conditions combined with the timing of transfer of wells from Albpetrol results in production increases that are typically higher in the second and third quarters. As new wells come on stream, there is a build-up period in production, higher sand production and higher well servicing costs, which is typical for heavy oil wells in the first year of production. In addition, production levels can be affected by water disposal constraints, mechanical wellbore and isolation failures, increased water production coming from shallower and deeper zones, and a shortage of rig work-over capacity and specialised well servicing equipment. 
  
  
• The increase in royalties is related to higher oil prices and the greater number of wells being taken over from Albpetrol, which results in higher pre-existing production.
  
  
• Fluctuations of operating expenses is part of a continuing trend that results from operating efficiencies gained through greater experience in field operations and economies of scale as the proportionate share of fixed operating expenses declines with production increases.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

IFRS First Time Adoption

These consolidated financial statements have been prepared in accordance with IFRS.  These are the Company's first IFRS consolidated annual financial statements and IFRS 1 "First-time Adoption of IFRS" has been applied.

An explanation of how the transition to IFRS has affected the reported financial position, financial performance and cash flows of the Company is provided in note 23 to the consolidated financial statements. This note includes reconciliations of equity and total comprehensive income for comparative periods reported under previous GAAP to those reported for those periods under IFRS.  The Company's IFRS accounting policies are referred to in note 3 to the consolidated financial statements.

Accounting Policy Changes

The following discussion explains the significant difference between the Company's previous GAAP accounting policies and those applied by the Company under IFRS.  IFRS policies have been retrospectively and consistently applied except where specific IFRS 1 optional and mandatory exemptions permitted an alternative treatment upon transition to IFRS for first-time adopters.

Use of Estimates and Judgments

The preparation of financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, revenues and expenses. Actual results may differ from these estimates.

Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the year in which the estimates are revised and in any future years affected. Significant estimates and judgments made by management in the preparation of these consolidated financial statements are as follows:

Amounts recorded for decommissioning obligation and the related accretion expense requires the use of estimates with respect to the inflation and discount rates used and the amount and timing for decommissioning expenditures.  Other provisions are recognized in the period when it becomes probable that there will be a future cash outflow.

The estimated fair value of derivative financial instruments resulting in financial assets and liabilities, by their very nature is subject to estimation, due to the use of future oil and natural gas prices and the volatility in these prices.

Share-based payments are subject to the estimations of what the ultimate payout will be using pricing models such as the Black-Scholes option pricing model, which is based on significant assumptions such as volatility, dividend yield, forfeiture rate and expected term.

Tax interpretations, regulations and legislation in the various jurisdictions in which the Company operates are subject to change.  As such, income taxes are subject to measurement uncertainty.  Deferred income tax assets are assessed by management at the end of the reporting period to determine the likelihood that they will be realized from future taxable earnings.

The amounts recorded for depreciation and depletion of oil and natural gas properties are based on estimates of proved and probable reserves and future capital costs.  The ceiling test is based on estimates of proved and probable reserves, production rates, future commodity prices, future costs and other relevant assumptions.

Reconciliations from Canadian GAAP to IFRS

The following tables provide a summary reconciliation of Bankers' Statement of Financial Position at January 1, 2010 and December 31, 2010 from GAAP to IFRS:

The following table summarizes the statement of comprehensive income for the year ended December 31, 2010:

NEW ACCOUNTING STANDARDS TO BE ADOPTED

In May 2011, the IASB issued four new standards and two amendments. Five of these items related to consolidation, while the remaining one addresses fair value measurement. All of the new standards are effective for annual periods beginning on or after January 1, 2013. Early adoption is permitted.

IFRS 10 "Consolidated Financial Statements" introduces a new principle-based definition of control, applicable to all investees to determine the scope of consolidation. The standard provides the framework for consolidated financial statements and their preparation based on the principle of control.

IFRS 11 "Joint Arrangements" replaces IAS 31 "Interests in Joint Ventures". IFRS 11 divides joint arrangements into two types, each having its own accounting model. A "joint operation" continues to be accounted for using proportionate consolidation, where a "joint venture" must be accounted for using equity accounting. This differs from IAS 31, where there was the choice to use proportionate consolidation or equity accounting for joint ventures. A "joint operation" is defined as the joint operators having rights to the assets, and obligations for the liabilities, relating to the arrangement. In a "joint venture", the joint ventures' have rights to the net assets of the arrangement, typically through their investment in a separate joint venture entity.

IFRS 12 "Disclosure of Interests in Other Entities" is a new standard, which combines all of the disclosure requirements for subsidiaries, associates and joint arrangements, as well as unconsolidated structured entities.

IFRS 13 "Fair Value Measurement" is a new standard meant to clarify the definition of fair value, provide guidance on measuring fair value and improve disclosure requirements related to fair value measurement.

IAS 28 "Investments in Associates and Joint Ventures" has been amended as a result of the issuance of IFRS 11 and the withdrawal of IAS 31. The amended standard sets out the requirements for the application of the equity method when accounting for interest in joint ventures, in addition to interests in associates.

IAS 27 "Separate Financial Statements" has been amended to focus solely on accounting and disclosure requirements when an entity presents separate financial statements that are not consolidated financial statements.

In November 2009, the IASB published IFRS 9 "Financial Instruments", which covers the classification and measurement of financial assets as part of its project to replace IAS 39 "Financial Instruments: Recognition and Measurement." In October 2010, the requirements for classifying and measuring financial liabilities were added to IFRS 9. Under this guidance, entities have the option to recognize financial liabilities at fair value through earnings. If this option is elected, entities would be required to reverse the portion of the fair value change due to a company's own credit risk out of earnings and recognize the change in other comprehensive income. IFRS 9 is effective for the Company on January 1, 2015. Early adoption is permitted and the standard is required to be applied retrospectively.

The Company is currently evaluating the impact of adopting all of the newly issued and amended standards.

INTERNAL CONTROLS

The Company's President and Chief Executive Officer (CEO) and Executive Vice President, Finance and Chief Financial Officer (CFO) have designed, or caused to be designed under their supervision, disclosure controls and procedures (DC&P) and internal controls over financial reporting (ICOFR) as defined in National Instrument 52-109 certification of Disclosure in Issuer's Annual and Interim Filings in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with IFRS.

The DC&P have been designed to provide reasonable assurance that material information relating to Bankers is made known to the CEO and CFO by others and that information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by Bankers under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation. The Company's CEO and CFO have concluded, based on their evaluation as of December 31, 2011 that the Company's disclosure controls and procedures are effective to provide reasonable assurance that material information related to the issuer, is made known to them by others within the Company.

The CEO and CFO are required to cause the Company to disclose any change in the Company's ICOFR that occurred during the most recent interim period that has materially affected, or is reasonably likely to materially affect, the Company's ICOFR.  No changes in ICOFR were identified during such period that have materially affected or are reasonably likely to materially affect, the Company's ICOFR. There were no changes to ICOFR as a result of the transition to IFRS.

It should be noted, a control system, including the Company's DC&P and ICOFR, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objective of the control system will be met and it should not be expected that DC&P and ICOFR will prevent all errors or fraud.

OUTLOOK

The Company's capital program in 2012 will be $215 million, fully funded from projected cash flow based on an average $90 Brent oil price. The work program and budget will include the following:

• Drilling of 100 horizontal and vertical wells and completion of 60 well reactivations and workovers at the Patos-Marinza oilfield.
• Continuing the water disposal capacity expansion with additional water disposal drills and water control initiative with over 200 well isolations.
• Continuing the thermal pilot operations and drilling additional core wells for assessing future thermal development plans.
• Initiating social and environmental impact assessments, land permitting and material orders for the 35 kilometer second phase of the 70,000 bopd capacity pipeline from the Fier Hub to the Vlore export terminal with construction beginning in 2013.
• Expanding waterflood activities at the Kuçova oilfield with 5 injector conversions and 13 production reactivation wells.
• Drilling of 2 exploration wells on Block "F".
• Continuing with the environmental stewardship and social initiatives in our area of operations.
  

The notes are an integral part of these consolidated financial statements.

APPROVED BY THE BOARD

"Robert Cross"              Director   "Eric Brown"                    Director

Commitments (Note 22)

The notes are an integral part of these consolidated financial statements.

The notes are an integral part of these consolidated financial statements.

The notes are an integral part of these consolidated financial statements.

1. REPORTING ENTITY

Bankers Petroleum Ltd. (Company) is incorporated and domiciled in Canada and is engaged in the exploration for and development and production of oil in Albania. The Company is listed on the Toronto Stock Exchange and the Alternative Investment Market of the London Stock Exchange under the symbol BNK.

The consolidated financial statements include the accounts of the Company and its wholly-owned operating subsidiaries (Group) - Bankers Petroleum Albania Ltd. (BPAL), Bankers Petroleum International Limited (BPIL) and Sherwood International Petroleum Ltd (Sherwood).  BPAL and Sherwood are incorporated in the Cayman Islands and BPIL is incorporated in Jersey.

The Group operates in Albanian oilfields pursuant to Petroleum Agreements with Albpetrol Sh.A (Albpetrol), the state owned oil company, under Albpetrol's existing license with the Albanian National Agency for Natural Resources (AKBN). The Patos-Marinza and Kuçova agreements became effective in March 2006 and September 2007, respectively, and have a 25 year term with extension options at the Company's election for further five year increments, subject to government and regulatory approvals.

2. BASIS OF PREPARATION

(a) Statement of compliance

These consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) and are the Company's first IFRS consolidated annual financial statements.  IFRS 1 "First-time Adoption of IFRS" has been applied.

An explanation of how the transition to IFRS has affected the reported financial position, financial performance and cash flows of the Company is provided in note 23. This note includes reconciliations of equity and total comprehensive income for comparative periods and of equity at the date of transition reported under previous Canadian generally accepted accounting principles (GAAP) to those reported for those periods under IFRS.

The consolidated financial statements were authorized for issue by the Board of Directors on March 16, 2012.

(b) Basis of presentation and measurement

The consolidated financial statements have been prepared on the historical cost basis except for derivative financial instruments and held-for-trading financial assets measured at fair value with changes in fair value recorded in profit or loss.  The methods used to measure fair values are discussed in note 4.

(c) Functional and presentation currency

Items included in the financial statements of each of the Group's entities are measured using the currency of the primary economic environment in which the entity operates (functional currency).  The functional currency of the parent entity is Canadian dollars. These consolidated financial statements are presented in United States (US) dollars (presentation currency), which is the functional currency of the Company's operating subsidiaries.

Unless where otherwise noted, the consolidated financial statements are presented in thousands of US dollars.

(d) Use of estimates and judgments

The preparation of the consolidated financial statements in conformity with IFRS requires management to make estimates and use judgment regarding the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities as at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the year.  By their nature, estimates are subject to measurement uncertainty and changes in such estimates in future periods could require a material change in the financial statements. Accordingly, actual results may differ from the estimated amounts as future confirming events occur. Significant estimates and judgments made by management in the preparation of these consolidated financial statements are as follows:

Recoverability of asset carrying values

The recoverability of development and production asset carrying values are assessed at a cash generating unit (CGU) level. Determination of what constitutes a CGU is subject to management judgments. The asset composition of a CGU can directly impact the recoverability of the assets included therein. The key estimates used in the determination of cash flows from oil reserves include the following:

Depletion and depreciation

Amounts recorded for depletion and depreciation and amounts used for impairment calculations are based on estimates of total proved and probable petroleum and natural gas reserves and future development capital. By their nature, the estimates of reserves, including the estimates of future prices, costs and future cash flows, are subject to measurement uncertainty. Accordingly, the impact to the consolidated financial statements in future periods could be material.

Decommissioning obligation

Amounts recorded for decommissioning obligation and the related accretion expense require the use of estimates with respect to the amount and timing of decommissioning expenditures. Actual costs and cash outflows can differ from estimates because of changes in laws and regulations, public expectations, market conditions, discovery and analysis of site conditions and changes in technology. Other provisions are recognized in the period when it becomes probable that there will be a future cash outflow.

Financial instruments

The estimated fair value of derivative financial instruments resulting in financial assets and liabilities, by their very nature are subject to measurement uncertainty.

Share-based payments

Compensation costs recognized for share-based payment plans are subject to the estimation of what the ultimate payout will be using pricing models such as the Black-Scholes option pricing model which is based on significant assumptions such as volatility, dividend yield and expected term of options and warrants. Several compensation plans are also performance based and are subject to management's judgment as to whether or not performance criteria will be met.

Deferred taxes

Tax interpretations, regulations and legislation in the various jurisdictions in which the Company operates are subject to change. As such income taxes are subject to measurement uncertainty. Deferred income tax assets are assessed by management at the end of the reporting period to determine the likelihood that they will be realized from future taxable earnings.

3. SIGNIFICANT ACCOUNTING POLICIES

The accounting policies set out below have been applied consistently to all periods presented in these consolidated financial statements, and have been applied consistently by the Group.

(a) Basis of consolidation

(b) Foreign currency transactions

The functional currency for each entity is the currency of the primary economic environment in which it operates.  The functional currency of the Albanian segment is the US dollar.  Foreign currency denominated transactions and balances for this segment are translated to US dollars as follows:

The results and financial position of the Canadian segment has a Canadian dollar functional currency, which is different from the presentation currency. The Company translates foreign currency denominated transactions and balances related to the Canadian segment into the presentation currency as follows:

(c) Financial instruments

(d) Property, plant and equipment (PP&E) and intangible exploration assets

(e) Inventory

Inventory is comprised of crude oil, diluent, diesel and other stocks, and is valued at the lower of average cost of production and net realizable value (estimated selling price in the ordinary course of business, less the costs of completion and costs necessary to make the sale).

(f) Impairment

(g) Share-based payments

The grant date fair value of warrants awarded to employees, directors and service providers is measured using the Black-Scholes option pricing model.  The grant date fair value of options awarded to employees, directors and service providers is measured using the Black-Scholes option pricing model and recognized in the statement of comprehensive income, with a corresponding increase in contributed surplus over the vesting period. A forfeiture rate is estimated on the grant date and is adjusted to reflect the actual number of options that vest.  Upon exercise of the option, consideration received, together with the amount previously recognized in contributed surplus, is recorded as an increase to share capital.

(h) Decommissioning obligation

A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax risk-free rate that reflects current market assessments of the time value of money and the risks specific to the liability. Provisions are not recognized for future operating losses.

The Company's activities give rise to dismantling, decommissioning and site remediation activities when retiring tangible long-life assets such as producing well sites and facilities. Provision is made for the estimated cost of site restoration and capitalized in the relevant asset category.

Decommissioning obligation is measured at the present value of management's best estimate of expenditures required to settle the present obligation at the balance sheet date. Subsequent to the initial measurement, the obligation is adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as accretion within finance expenses whereas increases/decreases due to changes in the estimated future cash flows are capitalized. Such capitalized costs for resource properties are amortized as part of depletion and depreciation using the unit-of-production method. Actual costs incurred upon settlement of the decommissioning obligation are charged against the provision to the extent the provision was established.

(i) Revenue

Revenue from the sale of the Company's oil is recorded when the significant risks and rewards of ownership of the product is transferred to the buyer which is usually when legal title passes to the external party. This is generally at the time the product is shipped (export sales) or delivered to the refinery (domestic sales).

(j) Finance income and expense

Finance expense comprises interest and bank charges, accretion of decommissioning obligation, amortization of deferred financing costs, accretion of long-term debt and any impairment losses recognized on financial assets.

Interest income is recognized as it accrues in profit or loss, using the effective interest method.

Foreign currency gains and losses, reported under finance income and expense, are reported on a net basis.

(k) Income tax

Income tax expense comprises current and deferred tax. Income tax expense is recognized in profit or loss except to the extent that it relates to items recognized directly in equity.

Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.

Deferred tax is recognized on the temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination. In addition, deferred tax is not recognized for taxable temporary differences arising on the initial recognition of goodwill. Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, but they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously.

A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

(l)  Earnings per share

Basic earnings per share is calculated by dividing the net earnings or loss attributable to common shareholders of the Company by the weighted average number of common shares outstanding during the period. Diluted earnings per share is determined by adjusting the net earnings or loss attributable to common shareholders and the weighted average number of common shares outstanding for the effects of dilutive instruments such as options and warrants granted. The dilutive effect on earnings per share is recognized on the use of the proceeds that could be obtained upon exercise of options, warrants and similar instruments.  It is assumed that the proceeds would be used to purchase common shares at the average market price during the period.

(m) New standards not yet adopted

In May 2011, the IASB issued four new standards and two amendments. Five of these items related to consolidation, while the remaining one addresses fair value measurement. All of the new standards are effective for annual periods beginning on or after January 1, 2013. Early adoption is permitted.

IFRS 10 "Consolidated Financial Statements" introduces a new principle-based definition of control, applicable to all investees to determine the scope of consolidation. The standard provides the framework for consolidated financial statements and their preparation based on the principle of control.

IFRS 11 "Joint Arrangements" replaces IAS 31 "Interests in Joint Ventures". IFRS 11 divides joint arrangements into two types, each having its own accounting model. A "joint operation" continues to be accounted for using proportionate consolidation, where a "joint venture" must be accounted for using equity accounting. This differs from IAS 31, where there was the choice to use proportionate consolidation or equity accounting for joint ventures. A "joint operation" is defined as the joint operators having rights to the assets, and obligations for the liabilities, relating to the arrangement. In a "joint venture", the joint ventures partners have rights to the net assets of the arrangement, typically through their investment in a separate joint venture entity.

IFRS 12 "Disclosure of Interests in Other Entities" is a new standard, which combines all of the disclosure requirements for subsidiaries, associates and joint arrangements, as well as unconsolidated structured entities.

IFRS 13 "Fair Value Measurement" is a new standard meant to clarify the definition of fair value, provide guidance on measuring fair value and improve disclosure requirements related to fair value measurement.

IAS 28 "Investments in Associates and Joint Ventures" has been amended as a result of the issuance of IFRS 11 and the withdrawal of IAS 31. The amended standard sets out the requirements for the application of the equity method when accounting for interest in joint ventures, in addition to interests in associates.

IAS 27 "Separate Financial Statements" has been amended to focus solely on accounting and disclosure requirements when an entity presents separate financial statements that are not consolidated financial statements.

In November 2009, the IASB published IFRS 9 "Financial Instruments", which covers the classification and measurement of financial assets as part of its project to replace IAS 39 "Financial Instruments: Recognition and Measurement." In October 2010, the requirements for classifying and measuring financial liabilities were added to IFRS 9. Under this guidance, entities have the option to recognize financial liabilities at fair value through earnings. If this option is elected, entities would be required to reverse the portion of the fair value change due to a company's own credit risk out of earnings and recognize the change in other comprehensive income. IFRS 9 is effective for the Company on January 1, 2015. Early adoption is permitted and the standard is required to be applied retrospectively.

The Company is currently evaluating the impact of adopting all of the newly issued and amended standards.

4. DETERMINATION OF FAIR VALUES

A number of the Company's accounting policies and disclosures require the determination of fair value, for both financial and non-financial assets and liabilities. Fair values have been determined for measurement and/or disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining fair values is disclosed in the notes specific to that asset or liability.

(a)     Property, plant and equipment (PP&E)

The fair value of PP&E and exploration and evaluation (E&E) assets recognized in a business combination, is based on market values. The market value of PP&E and E&E assets is the estimated amount for which the assets could be exchanged on the acquisition date between a willing buyer and a willing seller in an arm's length transaction after proper marketing wherein the parties had each acted knowledgeably, prudently and without compulsion. The market value of oil and natural gas interests (included in PP&E) and intangible exploration assets is estimated with reference to the discounted cash flows expected to be derived from oil and natural gas production based on externally prepared reserve reports. The risk-adjusted discount rate is specific to the asset with reference to general market conditions.

(b) Cash and cash equivalents, restricted cash, short-term investments, accounts receivable, accounts payables and accrued liabilities and long-term debt.

The fair value of cash and cash equivalents, restricted cash, short-term investments, accounts receivable and accounts payable and accrued liabilities is estimated as the present value of future cash flows, discounted at the market rate of interest at the reporting date. At December 31, 2011 and 2010, the fair value of these balances approximated their carrying value due to their short term to maturity, or in the case of long-term debt, the fair value approximates its carrying value as it bears interest at floating rates.

(c) Derivatives

The fair value of financial commodity contracts is determined by discounting the difference between the contracted prices and published forward price curves as at the balance sheet date, using the remaining contracted oil and natural gas volumes and a risk-free interest rate (based on published government rates).

(d) Stock options and warrants

The fair value of employee stock options and warrants is measured using a Black-Scholes option pricing model. Measurement inputs include share price on measurement date, exercise price of the instrument, expected volatility (based on weighted average historic volatility adjusted for changes expected due to publicly available information), weighted average expected life of the instruments (based on historical experience and general option and warrant holder behavior), expected dividends, expected forfeiture rate and the risk-free interest rate (based on government bonds).

(e) Financial assets and liabilities

The following tables provide fair value measurement information for financial assets and liabilities as of December 31, 2011 and 2010.  The carrying value of cash and cash equivalents, restricted cash, short-term investments, accounts receivable, accounts payable and accrued liabilities and long-term debt included in the consolidated statement of financial position approximate fair value due to the short term nature of those instruments or the indexed rate of interest on the long-term debt.  These assets and liabilities are not included in the following tables:

Level 1 fair value measurements are based on unadjusted quoted market prices. Cash and cash equivalents have been classified as level 1.

Level 2 fair value measurements are based on valuation models and techniques where the significant inputs are derived from quoted indices.

Level 3 fair value measurements are those with inputs for the asset or liability that are not based on observable market data.

5. FINANCIAL RISK MANAGEMENT

(a) Overview

The Company's activities expose it to a variety of financial risks that arise as a result of its exploration, development, production, and financing activities such as:

• credit risk;
• liquidity risk; and
• market risk.

This note presents information about the Company's exposure to each of the above risks, the Company's objectives, policies and processes for measuring and managing risk, and the Company's management of capital. Further quantitative disclosures are included throughout these consolidated financial statements.

The Board of Directors oversees managements' establishment and execution of the Company's risk management framework. Management has implemented and monitors compliance with risk management policies. The Company's risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company's activities.

(b) Credit risk

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from the Company's receivables from petroleum refineries relating to accounts receivable.

In Canada, no amounts are considered past due or impaired.

The carrying amount of accounts receivable represents the maximum credit exposure.  As of December 31, 2011 and 2010, the Company does not have an allowance for doubtful accounts and did not provide for any doubtful accounts nor was it required to write-off any receivables.

As at December 31, 2011, the Company's receivables consisted of $55.8 million (2010 - $29.0 million) of receivables from petroleum refineries and $0.2 million (2010 - $0.2 million) of other trade receivables, as summarized below: