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.

Results at a Glance (US$000, except as noted)
	2011		2010		Change (%)
Oil revenue	339,918		170,376		100
Net operating income	169,653		81,103		109
Net income	35,996		10,525		242
Funds generated from operations	147,940		70,871		109
Capital expenditures	242,754		119,717		103
Average production (bopd)	12,784		9,597		33
Average price ($/barrel)	72.84		48.64		50
Netback ($/barrel)	36.36		23.15		57
	December 31
	2011		2010
Cash and deposits	54,013		108,119
Working capital	80,282		130,920
Total assets	661,216		465,598
Long-term debt	46,692		21,815
Shareholders' equity	412,679		346,267

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:

($000s)				2011		2010
Cash provided by operating activities				132,197		49,157
Change in non-cash working capital				15,743		21,714
Funds generated from operations				147,940		70,871

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.

 

OVERVIEW & SELECTED ANNUAL INFORMATION
($000s, except as noted)						Year ended December 31
Results at a Glance						2011		2010		2009^(1)
Financial
	Oil revenue					339,918		170,376		86,614
	Net operating income					169,653		81,103		31,496
	Net income (loss)					35,996		10,525		(150)
	Per share - basic ($)					0.146		0.044		(0.001)
		- diluted ($)				0.141		0.043		(0.001)
	Funds generated from operations					147,940		70,871		25,422
	Per share - basic ($)					0.599		0.299		0.123
	Additions to property, plant and equipment					242,754		119,717		38,324
Operating
	Average sales (bopd)					12,784		9,597		6,438
	Average price ($/barrel)					72.84		48.64		36.86
	Netback ($/barrel)					36.36		23.15		13.40
	Average Brent oil price ($/barrel)					111.26		79.50		61.67
						December 31
						2011		2010		2009^(1)
Cash and deposits						54,013		108,119		68,270
Working capital						80,282		130,920		75,414
Total assets						661,216		465,598		306,055
Long-term debt						46,692		21,815		23,446
Shareholders' equity						412,679		346,267		214,777

^(1)	^2009 comparative figures are prepared in accordance with Canadian GAAP.

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

Commodity price and foreign exchange benchmarks for the past two years are as follows:
		2011		2010
Brent oil average price ($/barrel)		111.26		79.50
US/ Canadian dollar year-end exchange rate		1.0170		0.9946
US/ Canadian dollar average exchange rate		0.9891		1.0299

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

Below is a summary of Bankers' performance over the last eight quarters.
	2011
($000s, except as noted)	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Year
		$/bbl		$/bbl		$/bbl		$/bbl		$/bbl
Average sales (bopd)	11,894		12,152		13,667		13,399		12,784
Oil revenue	72,736	67.95	85,184	77.03	93,650	74.48	88,348	71.67	339,918	72.84
Royalties	13,755	12.85	13,062	11.81	18,457	14.68	18,667	15.14	63,941	13.70
Operating expenses	11,597	10.83	14,637	13.24	17,328	13.78	17,302	14.04	60,864	13.04
Sales and transportation	7,550	7.05	10,241	9.26	12,967	10.31	14,702	11.93	45,460	9.74
Net operating income	39,834	37.22	47,244	42.72	44,898	35.71	37,677	30.56	169,653	36.36

	2010
($000s, except as noted)	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Year
		$/bbl		$/bbl		$/bbl		$/bbl		$/bbl
Average sales (bopd)	8,282		9,830		9,826		10,424		9,597
Oil revenue	35,149	47.16	42,147	47.12	42,135	46.61	50,945	53.12	170,376	48.64
Royalties	7,190	9.65	8,367	9.35	8,284	9.16	9,841	10.26	33,682	9.62
Operating expenses	7,925	10.63	8,892	9.94	9,401	10.40	10,526	10.98	36,744	10.49
Sales and transportation	4,395	5.90	4,535	5.07	4,804	5.31	5,113	5.33	18,847	5.38
Net operating income	15,639	20.98	20,353	22.76	19,646	21.74	25,465	26.55	81,103	23.15

	2011
($000s, except as noted)	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Year
Financial
Funds generated from operations	29,948	43,220	42,099	32,673	147,940
Net income	11,219	10,800	13,696	281	35,996
Adjusted earnings^(1)	12,620	11,415	8,698	6,167	38,900
Basic earnings per share ($)	0.046	0.044	0.055	0.001	0.146
General and administrative	2,858	3,580	3,536	3,799	13,773
Total assets	522,476	565,340	612,348	661,216	661,216
Capital expenditures	51,930	69,388	65,147	56,289	242,754
Bank loans	20,416	33,769	40,348	70,372	70,372

	2010
($000s, except as noted)	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Year
Financial
Funds generated from operations	13,289	18,254	16,036	23,292	70,871
Net income (loss)	(363)	3,300	2,958	4,630	10,525
Basic earnings (loss) per share ($)	(0.002)	0.014	0.012	0.019	0.044
General and administrative	2,456	2,327	2,462	3,305	10,550
Total assets	329,036	337,007	442,345	465,598	465,598
Capital expenditures	26,170	28,724	27,456	37,367	119,717
Bank loans	26,418	27,330	23,887	25,829	25,829

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

DISCUSSION OF OPERATING RESULTS

Sales, Revenue and Netback

				2011				2010				%
Average sales (bopd)				12,784				9,597				33
Oil revenue ($000s)				339,918				170,376				100
Netback ($/barrel)
Average price				72.84				48.64				50
Royalties				13.70				9.62				43
Operating expenses				13.04				10.49				24
Sales and transportation				9.74				5.38				81
Netback				36.36				23.15				57

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)

		2011					2010	%
		Patos- Marinza	Kuçova	Total Albania			Total Albania
Proved
	Developed Producing	25.8	-	25.8			17.3	49
	Developed Non-Producing	-	-	-			-	-
	Undeveloped	143.4	3.2	146.6			102.9	42
Total Proved		169.2	3.2	172.4			120.2	43
Probable		87.1	7.6	94.7			117.4	(19)
Total Proved Plus Probable		256.3	10.8	267.1			237.6	12
Possible		138.9	20.3	159.2			189.0	(16)
Total Proved, Probable & Possible		395.2	31.1	426.3			426.6	-

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

		2011				2010	%
		Patos- Marinza	Kuçova	Total Albania		Total Albania
Proved
	Developed Producing	347	-	347		220	58
	Developed Non-Producing	-	-	-		-	-
	Undeveloped	647	22	669		729	(8)
Total Proved		994	22	1,016		949	7
Probable		854	103	957		1,019	(6)
Total Proved Plus Probable		1,848	125	1,973		1,968	-
Possible		1,377	344	1,721		1,584	9
Total Proved, Probable & Possible		3,225	469	3,694		3,552	4

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
($000s)					2011		2010
Drilling programs					110,230		69,572
Well re-activations					25,564		8,439
Work-over program					12,208		11,175
Base program
	Facility/infrastructure				12,651		5,438
	Environmental stewardship				8,652		789
	Water control/disposal				16,466		6,475
	Pipeline/sales infrastructure				12,792		4,387
	Other base capital				7,886		2,564
Evaluation area					-		7,983
Thermal project					11,770		327
Kuçova oilfield					1,697		63
Block "F"					1,454		-
Oilfield equipment					20,190		2,345
Corporate and other					1,194		160
					242,754		119,717

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:

($000s)			Albania			Canada			Total
2012			550			507			1,057
2013			350			507			857
2014			346			42			388
2015			346			-			346
2016			346			-			346
2017 and after			1,210			-			1,210
			3,148			1,056			4,204

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:

($000s)
2012							13,187
2013							35,589
2014							9,746
2015							9,450
2016							1,200
2017							1,200
							70,372

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.

(a)		IFRS 1 election for full cost oil and gas entities
		On transition to IFRS on January 1, 2010, Bankers used certain exemptions allowed under IFRS 1 "First Time Adoption of IFRS".
		IFRS 1 allows an entity that used full cost accounting under its previous GAAP to elect, at the time of adoption to IFRS, to measure oil and gas assets in the development and production phases by allocating the amount determined under the entity's previous GAAP for those assets to the underlying assets pro rata using reserve volumes or reserve values as of that date.  Bankers used reserve values as at January 1, 2010 to allocate the cost of development and production assets to cash generating units.
		As Bankers elected the oil and gas assets IFRS 1 exemption, the asset retirement obligation (ARO) exemption available to full cost entities was also elected.  This exemption allows for the re-measurement of ARO on IFRS transition with the offset to retained earnings.
		Bankers has elected the IFRS 1 optional exemption that allows an entity to use the IFRS rules for business combinations on a prospective basis rather than re-stating all business combinations.  In respect of acquisitions prior to January 1, 2010, any goodwill represents the amount recognized under Canadian GAAP.
		Bankers has elected the IFRS 1 exemption that allows the Company an exemption on IFRS 2 "Share-Based Payments" to equity instruments which vested and settled before the Company's transition date to IFRS.
		Bankers has elected the IFRS 1 exemption that allows the Company an exemption on IAS 21 "The Effects of Change in Foreign Exchange Rates".  The cumulative translation differences for all foreign operations are deemed to be zero at the date of transition to IFRS. Any retrospective translation differences are recognized in opening retained earnings.
		The use of the IFRS 1 election for full cost oil and gas entities did not have a material impact on the statement of financial position at January 1, 2010.
		Pre-exploration and evaluation expenditures of $0.1 million have been written off with a corresponding change to deficit at January 1, 2010.
(b)		Decommissioning obligation
		Under Canadian GAAP, ARO were discounted at a credit-adjusted risk-free rate of 10%.  Under IFRS, the estimated cash flow to abandon and remediate the wells and facilities has been risk adjusted therefore the provision is discounted at a risk-free rate in effect at the end of each reporting period.  The change in the decommissioning obligation each period as a result of changes in the discount rate will result in an offsetting charge to PP&E.  Upon transition to IFRS, the impact of this change was a $0.9 million increase in the decommissioning obligation with a corresponding increase to the deficit on the statement of financial position.
		As a result of the change in discount rate, the decommissioning obligation accretion expense decreased by $0.1 million during the year ended December 31, 2010, due to the lower discount rate.
		Under IFRS a separate line item is required in the statement of comprehensive income for finance costs.  The items under previous GAAP that were reclassified to finance expense were interest and bank charges, net foreign exchange loss, accretion of decommissioning obligation and amortization of deferred financing costs.
(c)		Share-based payments
		Under Canadian GAAP, the Company recognized an expense related to their share-based payments on a graded method of expense and did not incorporate a forfeiture rate at the grant date. Under IFRS, the Company is required to recognize the expense over the individual vesting periods for the graded vesting of awards and estimate a forfeiture rate at the date of grant and update it throughout the vesting period.  The impact on transition was a decrease in contributed surplus of $0.4 million with the offset recorded against deficit.
		For the year ended December 31, 2010, incorporation of a forfeiture rate resulted in a decrease to share-based payments of $0.2 million.
(d)		Depletion policy
		Upon transition to IFRS, the Company adopted a policy of depleting its oil properties on a unit of production basis over proved plus probable reserves. The depletion policy under Canadian GAAP was based on units of production over proved reserves. In addition, depletion was calculated on the Albanian consolidated cost centre under Canadian GAAP.  IFRS requires depletion and depreciation to be calculated based on individual components, separately.  Accordingly, under IFRS, major workover expenditures have been depreciated on a straight-line basis over an estimated useful life of 5 years, whereas under Canadian GAAP, these expenditures were depleted with the oil properties on a unit-of-production basis over total proved reserves.
		There was no impact of this difference on adoption of IFRS at January 1, 2010 as a result of the IFRS 1 election as discussed above.
		For the year ended December 31, 2010, depletion and depreciation was reduced by $4.6 million with a corresponding change to PP&E.
(e)		Capitalized costs
		Under IFRS, employee costs included in general and administrative charges and share-based payments are capitalized to the extent they are directly attributable to PP&E and E&E.  The Company has adjusted its capitalization policy to comply with IFRS.  For the year ended December 31, 2010, $2.3 million of such costs are expensed under IFRS that were previously capitalized under previous Canadian GAAP.
(f)		Foreign currency translations
		IFRS requires that the functional currency of each entity in a consolidated group be determined separately based on the currency of the primary economic environment in which the entity operates.  A list of primary and secondary indicators is used under IFRS in this determination and these differ in content and emphasis to a certain degree from those factors under Canadian GAAP.  The parent company operated with US dollar as functional currency under Canadian GAAP.  The Company re-assessed the determination of the functional currency for the parent company and determined the Canadian dollar as the functional currency for this entity under IFRS.  The impact of the change in functional currency was an adjustment to deferred financing costs, property, plant and equipment and retained earnings.  The adjustment to retained earnings at the date of transition was $1.3 million (using the optional IFRS 1 exemption discussed earlier).  For the year ended December 31, 2010, the currency translation adjustment was other comprehensive income of $6.1 million.
(g)		Deferred income taxes
		The adjustment to deferred income taxes on transition relates to the opening adjustment to the decommissioning obligation and pre-exploration and evaluation costs.  The deferred income tax impact of the opening adjustment was a reduction in deferred tax liability of $0.5 million with the corresponding change recorded in deficit.
		Under IFRS, the acquisition of an asset other than in a business combination does not give rise to any deferred income taxes based on the initial recognition exemption.  Under Canadian GAAP, any related deferred income taxes were added to the cost of the asset.  Accordingly, deferred income taxes recorded on capitalized share-based payments under Canadian GAAP have been adjusted by approximately $6.6 million for the year ended December 31, 2010.
		For the year ended December 31, 2010, deferred income tax expense increased by $1.2 million as a result of all related reconciling items between Canadian GAAP and IFRS presentation.

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:

										January 1, 2010
($000s)										Canadian GAAP				Effect of transition to IFRS				IFRS
Current assets										$	99,558			$	-			$	99,558
Non-current assets											205,262				1,235				206,497
Total assets										$	304,820			$	1,235			$	306,055
Current liabilities										$	24,144			$	-			$	24,144
Non-current liabilities											66,716				418				67,134
Shareholders' equity											213,960				817				214,777
Total liabilities and shareholders' equity										$	304,820			$	1,235			$	306,055

								December 31, 2010
($000s)										Canadian GAAP				Effect of transition to IFRS				IFRS
Current assets										$	158,175			$	-			$	158,175
Non-current assets											309,239				(1,816)				307,423
Total assets										$	467,414			$	(1,816)			$	465,598
Current liabilities										$	27,255			$	-			$	27,255
Non-current liabilities											96,852				(4,776)				92,076
Shareholders' equity											343,307				2,960				346,267
Total liabilities and shareholders' equity										$	467,414			$	(1,816)			$	465,598

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

								For Year Ended December 31, 2010
($000s)										Canadian GAAP				Effect of transition to IFRS				IFRS
Total Revenue										$	137,426			$	(732)			$	136,694
Total Expenses											99,618				(277)				99,341
Income before financing items and income tax											37,808				(455)				37,353
Financing items											-				(2,080)				(2,080)
Income before income taxes											37,808				(2,535)				35,273
Income taxes											(23,543)				(1,205)				(24,748)
Net income for the year											14,265				(3,740)				10,525
Other comprehensive income											-				6,094				6,094
Comprehensive income for the year										$	14,265			$	2,354			$	16,619

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.
  

BANKERS PETROLEUM LTD.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
FOR THE YEARS ENDED DECEMBER 31
(Expressed in thousands of US dollars, except per share amounts)
												Note					2011				2010
Revenues																	$	339,918			$	170,376
Royalties																		(63,941)				(33,682)
																		275,977				136,694
Unrealized loss on financial commodity contracts												5(d)						(2,904)				-
																		273,073				136,694
Operating expenses																		60,864				36,744
Sales and transportation expenses																		45,460				18,847
General and administrative expenses																		13,773				10,550
Depletion and depreciation												10						40,367				22,511
Share-based payments												17						11,041				7,900
																		171,505				96,552
																		101,568				40,142
Net finance expense												7						6,223				4,869
Income before income tax																		95,345				35,273
Deferred income tax expense												9						(59,349)				(24,748)
Net income for the year																		35,996				10,525
Other comprehensive income
	Currency translation adjustment																	315				6,094
Comprehensive income for the year																	$	36,311			$	16,619
Basic earnings per share												14					$	0.146			$	0.044
Diluted earnings per share												14					$	0.141			$	0.043

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

APPROVED BY THE BOARD

"Robert Cross"              Director   "Eric Brown"                    Director

BANKERS PETROLEUM LTD.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
(Expressed in thousands of US dollars)
ASSETS
													Note						December 31 2011				December 31 2010				January 1 2010
Current assets
	Cash and cash equivalents												12					$	49,013			$	106,619			$	59,495
	Short-term investments																		-				-				7,275
	Restricted cash												21						5,000				1,500				1,500
	Accounts receivable																		56,006				29,233				23,358
	Inventory												20						14,412				4,199				2,031
	Deposits and prepaid expenses																		17,463				16,624				5,899
	Financial commodity contracts												5(d)						3,684				-				-
																			145,578				158,175				99,558
Non-current assets
	Note receivable																		-				-				2,749
	Deferred financing costs												11						-				13,980				15,824
	Property, plant and equipment												10						515,638				293,443				187,924
																		$	661,216			$	465,598			$	306,055
LIABILITIES
Current liabilities
	Accounts payable and accrued liabilities																	$	52,109			$	23,241			$	19,505
	Current portion of long-term debt												16						13,187				4,014				4,639
																			65,296				27,255				24,144
Non-current liabilities
	Long-term debt												16						46,692				21,815				23,446
	Decommissioning obligation												19						13,561				6,622				4,796
	Deferred tax liabilities												9						122,988				63,639				38,892
																			248,537				119,331				91,278
SHAREHOLDERS' EQUITY
Share capital													13						318,021				309,379				206,058
Warrants													15						1,540				1,597				1,739
Contributed surplus																			49,651				28,135				16,443
Accumulated other comprehensive income																			6,409				6,094				-
Retained earnings (deficit)																			37,058				1,062				(9,463)
																			412,679				346,267				214,777
																		$	661,216			$	465,598			$	306,055

Commitments (Note 22)

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

BANKERS PETROLEUM LTD.
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31
(Expressed in thousands of US dollars)
												Note					2011				2010
Cash provided by (used in):
Operating activities
	Net income for the year																$	35,996			$	10,525
	Depletion and depreciation																	40,367				22,511
	Amortization of deferred financing costs											11						734				2,789
	Accretion of long-term debt											11						2,555				-
	Accretion of decommissioning obligation											19						460				302
	Unrealized foreign exchange loss																	1,122				2,096
	Deferred income tax expense																	59,349				24,748
	Share-based payments																	11,041				7,900
	Unrealized loss on financial commodity contracts																	2,904				-
	Cash premiums paid for financial commodity contracts											5(d)						(6,588)				-
																		147,940				70,871
	Change in non-cash working capital											8						(15,743)				(21,714)
																		132,197				49,157
Investing activities
	Additions to property, plant and equipment																	(242,754)				(119,717)
	Restricted cash																	(3,500)				-
	Change in non-cash working capital											8						6,786				6,682
																		(239,468)				(113,035)
Financing activities
	Issue of shares for cash																	5,783				104,720
	Financing costs											11						(30)				(211)
	Increase (decrease) in long-term debt											16						44,543				(2,256)
	Share issue costs																	(167)				(4,333)
	Note receivable																	-				2,749
	Short-term investments																	-				7,275
																		50,129				107,944
Foreign exchange gain (loss) on cash and cash equivalents																		(464)				3,058
Increase (decrease) in cash and cash equivalents																		(57,606)				47,124
Cash and cash equivalents, beginning of year																		106,619				59,495
Cash and cash equivalents, end of year												12					$	49,013			$	106,619
Interest paid																	$	2,362			$	2,581
Interest received																	$	574			$	787

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

BANKERS PETROLEUM LTD.
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Expressed in thousands of US dollars, except number of common shares)
						Note			Number of common shares			Share capital				Warrants				Contributed surplus				Accumulated other comprehensive income				Retained earnings (deficit)				Total
Balance at January 1, 2010									228,272,165			$	206,058			$	1,739			$	16,443			$	-			$	(9,463)			$	214,777
Issue of common shares						13			12,903,228				96,153				-				-				-				-				96,153
Share issue costs						13			-				(4,333)				-				-				-				-				(4,333)
Share-based payments						17			-				-				-				14,484				-				-				14,484
Options exercised									2,342,330				8,120				-				(2,792)				-				-				5,328
Warrants exercised									1,277,267				3,381				(142)				-				-				-				3,239
Net income for the year									-				-				-				-				-				10,525				10,525
Currency translation adjustment									-				-				-				-				6,094				-				6,094
Balance at December 31, 2010									244,794,990				309,379				1,597				28,135				6,094				1,062				346,267
Share-based payments						17			-				-				-				24,485				-				-				24,485
Options exercised									2,728,446				8,348				-				(2,969)				-				-				5,379
Warrants exercised									174,333				461				(57)				-				-				-				404
Share issue costs									-				(167)				-				-				-				-				(167)
Net income for the year									-				-				-				-				-				35,996				35,996
Currency translation adjustment									-				-				-				-				315				-				315
Balance at December 31, 2011									247,697,769			$	318,021			$	1,540			$	49,651			$	6,409			$	37,058			$	412,679

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:

(i)				Reserves - Assumptions that are valid at the time of reserve estimation may change significantly when new information becomes available. Changes in forward price estimates, production costs or recovery rates may change the economic status of reserves and may ultimately result in reserves being restated.
(ii)				Oil prices - Forward price estimates are used in the cash flow model. Commodity prices can fluctuate for a variety of reasons including supply and demand fundamentals, inventory levels, exchanges rates, weather, and economic and geopolitical factors.
(iii)				Discount rate - The discount rate used to calculate the net present value of cash flows is based on estimates of an approximate industry peer group weighted average cost of capital. Changes in the general economic environment could result in significant changes to this estimate.

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

(i)				Subsidiaries
				Subsidiaries are entities controlled by the Company.  Control exists when the Company has the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities.  In assessing control, potential voting rights that currently are exercisable are taken into account.  The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases.
(ii)				Transactions eliminated on consolidation
				Intercompany balances and transactions, and any unrealized income and expenses arising from intercompany transactions, are eliminated in preparing the consolidated financial statements.

(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:

(i)				Monetary assets and liabilities are translated at the rates prevailing at each reporting date;
(ii)				Non-monetary assets and liabilities are translated to the functional currency at the historical exchange rate;
(iii)				Income and expenses for the period are translated at the average exchange rate for the period; and
(iv)				Gains and losses arising from foreign currency translation are recognized in net income.

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:

(i)				Assets and liabilities are translated at the closing rate at each reporting date;
(ii)				Income and expenses are translated at exchange rates at the dates of the transactions; and
(iii)				All resulting exchange differences are recognized in other comprehensive income.

(c) Financial instruments

(i)				Non-derivative financial instruments
				Non-derivative financial instruments are comprised of accounts receivable, note receivable, restricted cash, cash and cash equivalents, short-term investments, long-term debt and accounts payable and accrued liabilities. Non-derivative financial instruments are recognized initially at fair value plus, for instruments not at fair value, through profit or loss, net of directly attributable transaction costs.
				Subsequent measurement of all financial assets and liabilities except those held-for-trading and available-for-sale are measured at amortized cost determined using the effective interest rate method. Held-for-trading financial assets are measured at fair value with changes in fair value recognized in earnings. Available-for-sale financial assets are measured at fair value with changes in fair value recognized in comprehensive income and reclassified to earnings when impaired.
				Cash and cash equivalents and short-term investments are held-for-trading investments and the fair values approximate their carrying value due to their short-term nature. Cash and cash equivalents include cash and highly liquid investments with original maturities of three months or less. Accounts receivable is classified as loans and receivables and the fair value approximates their carrying value due to the short-term nature of these instruments.  The note receivable is classified as other financial assets and its fair value approximates the carrying value as it bears interest at market rates.  Accounts payable and accrued liabilities are classified as other financial liabilities and the fair value approximates their carrying value due to the short-term nature of these instruments.  Long-term debt is classified as other financial liabilities and their fair value approximates carrying value as they bear interest at market rates.
(ii)				Derivative financial instruments
				The Company has entered into certain financial derivative contracts in order to manage the exposure to market risks from fluctuations in commodity prices.  The derivative financial instruments are initiated within the guidelines of the Company's risk management policy and are not used for trading or speculative purposes.  The Company has not designated its financial derivative contracts as effective accounting hedges, and thus has not applied hedge accounting, even though the Company considers all commodity contracts to be economic hedges.  Derivative financial instruments are initially recognized at their fair value on the date the derivative contract is entered into and are subsequently re-measured at their fair value at each reporting period with unrealized gains and losses resulting from changes in the fair value recognized in profit and loss and realized gains and losses recorded when the instrument is settled. Transaction costs are recognized in profit or loss when incurred.
				Embedded derivatives are separated from the host contract and accounted for separately if the economic characteristics and risks of the host contract and the embedded derivative are not closely related, a separate instrument with the same terms as the embedded derivative would meet the definition of a derivative, and the combined instrument is not measured at fair value through profit and loss.  Changes in the fair value of separable embedded derivatives are recognized immediately in profit or loss.
(iii)				Share capital
				Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares and share options are recognized as a deduction from equity.

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

(i)				Recognition and measurement
				Exploration and evaluation expenditures
				Pre-license costs are recognized in the statement of comprehensive income as incurred.
				Exploration and evaluation (E&E) costs, including the costs of acquiring licenses and directly attributable general and administrative costs, initially are capitalized as either tangible or intangible E&E assets according to the nature of the assets acquired.  The costs are accumulated in cost centers by well, field or exploration area pending determination of technical feasibility and commercial viability.
				E&E assets are assessed for impairment if (i) sufficient data exists to determine technical feasibility and commercial viability, and (ii) facts and circumstances suggest that the carrying amount exceeds the recoverable amount.  For purposes of impairment testing, E&E assets are assessed at the exploration area level.
				The technical feasibility and commercial viability of extracting a mineral resource is considered to be determinable when proved and/or probable reserves are determined to exist.  A review of each exploration license or field is carried out, at least annually, to ascertain whether proved and/or probable reserves have been discovered.  Upon determination of proved and/or probable reserves, E&E assets attributable to those reserves are first tested for impairment and then reclassified from E&E assets to a separate category within property, plant and equipment referred to as oil and natural gas interests.
				Development and production costs
				Items of PP&E, which include oil and gas development and production assets, are measured at cost less accumulated depletion and depreciation and accumulated impairment losses. Development and production assets are grouped into CGU's for impairment testing.  The Company has grouped its development and production assets into the following CGU's:  the Patos-Marinza and Kuçova oilfields.
				When significant parts of an item of PP&E have different useful lives, they are accounted for as separate items (major components).
				Gains and losses on disposal of an item of PP&E are determined by comparing the net proceeds from disposal with the carrying amount of PP&E and are recognized in the statement of comprehensive income.
(ii)				Subsequent costs
				Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of PP&E are recognized as oil and natural gas interests only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in profit or loss as incurred.  Such capitalized oil and natural gas interests generally represent costs incurred in developing proved and/or probable reserves and bringing on or enhancing production from such reserves, and are accumulated on a field or geotechnical area basis. The carrying amount of any replaced or sold component is derecognized. The costs of the day-to-day servicing of property, plant and equipment are recognized in profit or loss as incurred.
(iii)				Depletion and depreciation
				The net carrying value of development or production assets is depleted using the unit-of-production method by reference to the ratio of production in the year to the related proved and probable reserves, taking into account estimated future development costs necessary to bring those reserves into production. These estimates are reviewed by independent reservoir engineers at least annually.
				Proved and probable reserves are estimated using independent reservoir engineer reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible.
				For other assets, depreciation is recognized in profit or loss on either a straight-line or declining balance method over the estimated useful lives of each part of an item of PP&E. Land is not depreciated.
				Workover costs are depreciated on a straight-line basis over 5 years.
				Equipment, furniture and fixtures are depreciated on the declining balance method at rates of 20% to 30%.
				Depreciation methods, useful lives and residual values are reviewed at each reporting date.

(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

(i)				Financial assets
				A financial asset is assessed at each reporting date to determine whether there is any objective evidence of impairment. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of that asset.
				An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate.
				Material financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics.
				All impairment losses are recognized in profit or loss.
				An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. For financial assets measured at amortized cost, the reversal is recognized in profit or loss.
(ii)				Non-financial assets
				The carrying amounts of the Company's non-financial assets, other than E&E assets and deferred tax assets, are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists, then the asset's recoverable amount is estimated. E&E assets are assessed for impairment when they are reclassified to PP&E, and also if facts and circumstances suggest that the carrying amount exceeds the recoverable amount.
				For the purpose of impairment testing, assets are grouped together into CGU's. The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs to sell.
				Fair value, less cost to sell, is determined as the amount that would be obtained from the sale of a CGU in an arm's length transaction between knowledgeable and willing parties.  The fair value, less cost to sell oil and gas assets is generally determined as the net present value of the estimated future cash flows expected to arise from the continued use of the CGU, including any expansion prospects, and its eventual disposal, using assumptions that an independent market participant may take into account.  These cash flows are discounted by an appropriate discount rate which would be applied by a market participant to arrive at a net present value of the CGU.
				Value in use is determined as the net present value of the estimated future cash flows expected to arise from the continued use of the asset in its present form and its eventual disposal.  Value in use is determined by applying assumptions specific to the Company's continued use and can only take into account approved future development costs.  Estimates of future cash flows used in the evaluation of impairment of assets are made using management's forecasts of commodity prices and expected production volumes.  The latter takes into account assessments of field reservoir performance and includes expectations about proved and unproved volumes, which are risk-weighted utilizing geological, production, recovery and economic projections.
				E&E assets are assessed at the exploration area level when they are assessed for impairment, both at the time of any triggering facts and circumstances as well as upon their eventual reclassification to producing assets.
				An impairment loss is recognized in profit or loss if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses recognized in respect of CGU's are allocated to reduce the carrying amounts of the other assets in the unit (group of units) on a pro rata basis.
				An impairment loss in respect of other assets recognized in prior years is assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset's carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation, if no impairment loss had been recognized.

(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:

													Fair value measurements using
December 31, 2011 ($000s)								Carrying amount				Fair value				Quoted prices in active markets (level 1)				Significant other observable inputs (level 2)				Significant unobservable inputs (level 3)
Financial assets
	Fair value of financial commodity contracts						$	3,684			$	3,684			$	-			$	3,684			$	-

Fair value measurements using

December 31, 2010 ($000s)

Carrying amount

Fair value

Quoted prices in active markets (level 1)

Significant other observable inputs (level 2)

Significant unobservable inputs (level 3)

Financial assets

Fair value of financial commodity contracts

$

-

$

-

$

-

$

-

$

-

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:

2011 ($000s)						Current				30-60 days				61- 90 days				Over 90 days				Total
Albania						$	28,697			$	1,287			$	5,076			$	20,767			$	55,827
Canada							179				-				-				-				179
						$	28,876			$	1,287			$	5,076			$	20,767			$	56,006

2010 ($000s)						Current				30-60 days				61- 90 days				Over 90 days				Total
Albania						$	25,590			$	3,019			$	408			$	-			$	29,017
Canada							216				-				-				-				216
						$	25,806			$	3,019			$	408			$	-			$	29,233

In Albania, the Company considers any amounts greater than 60 days as past due.  The accounts receivable, included in the table, past due or not past due are not impaired.  They are from counterparties with whom the Company has a history of collection and the Company considers the accounts receivable collectible. Domestic receivables are due by the end of the month following production and export receivables are collected within 30 days from the date of shipment.  The Company's policy to mitigate credit risk associated with these balances is to establish marketing relationships with a variety of purchasers.  Of the total receivables of $55.8 million (2010 - $29.0 million) in Albania, approximately $28.2 million (2010 - $9.2 million) is due from one domestic customer of which $25.8 million (2010 - $0.4 million) is past due.  The customer has confirmed the outstanding amount and the Company has finalized a repayment plan. 

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

The Company manages the credit exposure related to cash and cash equivalents and short-term investments by selecting counter parties based on credit ratings and monitors all investments to ensure a stable return, avoiding complex investment vehicles with higher risk such as asset backed commercial paper.

(c) Liquidity risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due. The Company's approach to managing liquidity is to ensure, as far as possible, that it will always have sufficient liquidity to meet its liabilities when due, under both normal and stressed conditions, without incurring unacceptable losses or risking damage to the Company's reputation.

Typically the Company ensures that it has sufficient cash on demand to meet expected operational expenses for a minimum period of 30 days, including the servicing of financial obligations; this excludes the potential impact of extreme circumstances that cannot reasonably be predicted, such as natural disasters.  To achieve this objective, the Company prepares annual capital expenditure budgets, which are regularly monitored and modified as considered necessary.  Further, the Company utilizes authorizations for expenditures on both operated and non-operated projects to further manage capital expenditures.  To facilitate the capital expenditure program, the Company has credit facilities with three international banks, as disclosed in note 16.  The Company also attempts to match its payment cycle with collection of petroleum revenues. The Company maintains a close working relationship with the banks that provide its credit facilities.

The contractual maturities of financial liabilities, at December 31, 2011, are as follows:

($000s)				Carrying Amount			2012					2013			2014					2015 and after
Accounts payable and accrued liabilities		$		52,109		$		52,109		$		-		$		-		$		-
Operating loan				12,298				12,298				-				-				-
Term loans				8,074				889				2,089				1,496				3,600
Revolving loans				50,000				-				33,500				8,250				8,250
		$		122,481		$		65,296		$		35,589		$		9,746		$		11,850

(d) Market risk

Market risk is the risk that changes in market prices, such as foreign exchange rates, interest rates and commodity prices, will affect the Company's income or the value of the financial instruments. The objective of market risk management is to manage and control market risk exposures within acceptable parameters, while optimizing the return.

Foreign currency exchange rate risk

Foreign currency exchange rate risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in foreign exchange rates.   As at December 31, 2011, a 10% change in the foreign exchange rate of the Canadian dollar (CAD) against the US dollar (USD), with all other variables held constant, would affect after tax net income for the year by $1.1 million (2010 - $6.9 million).  The sensitivity is lower in 2011 as compared to 2010 because of a decrease in Canadian dollar cash and cash equivalents outstanding. The average exchange rate during the year was 1 USD equals CAD$0.99 (2010 - 1 USD: CAD$1.03) and the exchange rate at December 31, 2011 was 1 USD equals CAD$1.02 (2010 - 1 USD: CAD$0.99).

As at December 31, 2011, a 10% change in the foreign exchange rate of the Albanian Lek against the USD, with all other variables held constant, would affect after tax net income for the year by $3.9 million (2010 - $1.8 million).  The sensitivity is higher in 2011 as compared to 2010 due to the increase in Albania Lek accounts payable and accrued liabilities.  The average exchange rate during the year was 1 USD equals 0.01 Lek (2010 - 1 USD: 0.01 Lek) and the exchange rate at December 31, 2011 was 1 USD equals 0.01 Lek (2010 - 1 USD: 0.01 Lek).

The Company had no forward foreign exchange rate contracts in place as at or during the years ended December 31, 2011 and 2010.

The following financial instruments were denominated in CAD and Albanian Lek:

		2011						2010
(000s)		CAD		Lek		USD		CAD		Lek		USD
Cash and cash equivalents		13,137		1,052		12,927		69,729		694		70,115
Accounts receivable		181		-		178		215		-		216
Accounts payable and accrued liabilities		(1,861)		(3,899,416)		(38,824)		(1,504)		(1,822,324)		(19,262)
		11,457		(3,898,364)		(25,719)		68,440		(1,821,630)		51,069

Interest rate risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Company is exposed to interest rate fluctuations on its operating, term and revolving loans which bear a floating rate of interest.  As at December 31, 2011, a 10% change in the interest rate, with all other variables held constant, would affect after tax net income for the year by $0.3 million (2010 - $0.2 million), based on the average debt balance outstanding during the year.  The sensitivity in 2011 is higher as compared to 2010 mainly due to the increase in revolving loans outstanding.

The Company has not entered into any mitigating interest rate hedges or swaps.

Commodity price risk

Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for oil are impacted by not only the relationship between the Canadian and US dollar but also world economic events that dictate the levels of supply and demand.

It is the Company's policy to economically hedge some oil sales through the use of various financial derivative forward sale contracts.  The Company does not apply hedge accounting for these contracts.  The Company's production is usually sold using "spot" or near term contracts, with prices fixed at the time of transfer of custody or on the basis of a monthly average market price.

The Company's primary revenues are from oil sales in Albania, priced on a quality differential basis, to the Brent oil price. As at December 31, 2011, a $1 per barrel change in the Brent oil price, with all other variables held constant, would affect after tax net income for the year by $1.2 million (2010 - $0.9 million).

At December 31, 2011, the Company had outstanding 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, 2012 to December 31, 2012.

The estimated fair value of the financial oil contracts has been determined for the amounts the Company would receive or pay to terminate the oil contracts at year-end.  The Company paid a $6.6 million premium to enter into these financial oil contracts on February 28, 2011. At December 31, 2011, the estimated fair value of the financial commodity contracts is $3.7 million (2010 - nil), resulting in an unrealized loss of $2.9 million for the year ended December 31, 2011 (2010 - nil).

(e) Capital management

The Company's policy is to maintain a strong capital base so as to maintain investor, creditor and market confidence and to sustain future development of the business. The Company manages its capital structure and makes adjustments to it in the light of changes in economic conditions and the risk characteristics of the underlying oil assets. The Company considers its capital structure to include shareholders' equity, long-term debt and working capital. In order to maintain or adjust the capital structure, the Company may issue shares and adjust its capital spending to manage current and projected debt levels.

The Company monitors capital based on the ratio of debt to funds from operations.  This ratio is calculated as net debt (outstanding long-term debt less working capital before current portion of long-term debt) divided by funds from operations (cash provided by operating activities before changes in non-cash working capital). The Company's strategy is to maintain a ratio of no more than 1.5 to 1. This ratio may increase at certain times as a result of acquisitions. In order to monitor this ratio, the Company prepares annual capital expenditure budgets, which are updated as necessary depending on varying factors including current and forecast prices, successful capital deployment and general industry conditions. The annual and updated budgets are approved by the Board of Directors.

As at December 31, 2011, the ratio of debt to funds from operations was a surplus of 0.16 (2010 - surplus of 1.54).  The lower surplus was due to the reduction in net debt from a surplus of $109.1 million to a surplus of $23.1 million and an increase in funds from operations from $70.9 million to $147.9 million.

There were no changes in the Company's approach to capital management during the year.

The Company's share capital is not subject to external restrictions; however, the long-term debt facility is based on certain covenants, all of which were met as at December 31, 2011 and 2010.  The Company has not paid or declared any dividends since the date of incorporation, nor are any contemplated in the foreseeable future.

6. KEY MANAGEMENT PERSONNEL COMPENSATION 

Key management personnel compensation includes all compensation paid to executive management and members of the Board of Directors and is comprised of the following:

($000s)						2011					2010
Salaries and wages					$	2,605			$		1,799
Short-term employee benefits						1,199					861
Termination benefits						404					-
Share-based payments*						12,820					9,792
					$	17,028			$		12,452

* Represents the amortization of share-based payments associated with options granted to  key management personnel as recorded in the financial statements.

7. FINANCE INCOME AND EXPENSE

($000s)				2011			2010
Finance income
	Interest income	$		640	$		732
	Net foreign exchange gain			-			71
		$		640	$		803
Finance expense
	Interest and bank charges	$		2,656	$		2,581
	Net foreign exchange loss			458			-
	Amortization of deferred financing costs (note 11)			734			2,789
	Accretion of long-term debt (note 11)			2,555			-
	Accretion of decommissioning obligation (note 19)			460			302
		$		6,863	$		5,672
Net finance expense		$		6,223	$		4,869

8. SUPPLEMENTAL INFORMATION

a) Changes in non-cash working capital

($000s)							2011			2010
Operating activities
Change in current assets
	Accounts receivable				$		(26,773)	$		(5,875)
	Inventory						(10,213)			(2,168)
	Deposits and prepaid expenses						(839)			(10,725)
Change in current liabilities
	Accounts payable and accrued liabilities						22,082			(2,946)
					$		(15,743)	$		(21,714)
Investing activities
Change in current liabilities
	Accounts payable and accrued liabilities				$		6,786	$		6,682

b) Income statement presentation

The Company's consolidated statement of comprehensive income is prepared primarily by nature of expense, with the exception of employee compensation costs, which are included in both operating and general and administrative expenses.

The following table details the amount of total employee compensation costs included in operating and general and administrative expenses in the consolidated statements of comprehensive income.

($000s)			2011			2010
Operating expenses		$		4,624	$	3,442
General and administrative expenses				5,575		3,406
Total employee compensation costs		$		10,199	$	6,849

9. INCOME TAX EXPENSE

Deferred income tax expense relates to the Albanian operations and results from the following:

($000s)			2011			2010
Net book value of property, plant and equipment		$		494,738	$	286,499
Decommissioning obligation				(13,561)		(6,622)
Cost recovery pool				(235,201)		(152,599)
Timing difference		$		245,976	$	127,278
Deferred tax liability at 50%		$		122,988	$	63,639

The Company's deferred tax liabilities result from the temporary differences between the carrying values and tax values of its Albanian assets and liabilities.

The cost recovery pool represents deductions for income taxes in Albania. Under the terms of the Petroleum Agreements in Albania, profit will be taxed at a rate of 50%.

The provision for income taxes reported differs from the amounts computed by applying the cumulative Canadian federal and provincial income tax rates to the income before tax provision due to the following:

($000s)								2011		2010
Income before income taxes						$		95,345	$		35,273
Statutory tax rate								26.5%			28.0%
								25,266			9,876
Difference in tax rates between Albania and Canada								27,929			11,215
Permanent differences								4,709			(632)
Unrecognized deferred tax assets								1,287			3,451
Other								158			838
Deferred income tax expense						$		59,349	$		24,748

The statutory tax rate was 26.5% in 2011 (2010 - 28.0%).  The decrease from 2010 to 2011 was due to a reduction in the 2011 Canadian corporate tax rates as part of a series of corporate tax rate reductions previously enacted by the Canadian federal government in 2007.

The significant components of the Company's deductible temporary differences associated with the unrecognized deferred tax asset are as follows:

($000s)			2011			2010
Non-capital loss (expiring in 2015-2031)		$		33,763	$	27,389
Capital loss				25,994		29,749
Financial commodity contracts				2,904		-
Share issue costs				1,573		3,529
Property, plant and equipment - Canada				942		713
		$		65,176	$	61,380

The Company has temporary differences associated with its investments in its foreign subsidiaries and branches.  As at December 31, 2011, the Company has no deferred tax liabilities in respect of these temporary differences.

10. PROPERTY, PLANT AND EQUIPMENT (PP&E)

($000s)				Petroleum Interests			Equipment, Furniture and Fixtures			Total
Cost or deemed cost
Balance at January 1, 2010			$	185,778	$		3,882	$		189,660
		Exchange differences		192			44			236
		Additions		126,063			1,761			127,824
Balance at December 31, 2010				312,033			5,687			317,720
		Exchange differences		(84)			(52)			(136)
		Additions		258,582			4,095			262,677
Balance at December 31, 2011			$	570,531	$		9,730	$		580,261

Accumulated depletion and depreciation
Balance at January 1, 2010		$	-	$						1,736	$		1,736
	Exchange differences		-							30			30
	Depletion and depreciation		-							566			22,511
Balance at December 31, 2010			21,945							2,332			24,277
	Exchange differences		-							(21)			(21)
	Depletion and depreciation		39,420							947			40,367
Balance at December 31, 2011		$	61,365	$						3,258	$		64,623

($000s)												Petroleum Interests			Equipment, Furniture and Fixtures		Total
Net book value
		At January 1, 2010									$	185,778	$		2,146	$	187,924
		At December 31, 2010									$	290,088	$		3,355	$	293,443
		At December 31, 2011									$	509,166	$		6,472	$	515,638

The depletion expense calculation for the year ended December 31, 2011 included $1.9 billion (2010 - $1.2 billion) for estimated future development costs associated with proved and probable reserves in Albania.

The Company capitalized general and administrative expenses and share-based payments of $14.8 million during the year ended December 31, 2011 (2010 - $7.8 million) that were directly related to exploration and development activities in Albania.

Included in PP&E as of December 31, 2011 are oilfield equipment of $37.7 million (2010 - $17.5 million) for utilization in future drilling, reactivation and infrastructure programs in the Patos-Marinza oilfield.

For the year ended December 31, 2011, costs associated with the Kuçova oilfield of approximately $5.4 million were not depleted as production has not commenced.

For the years ended December 31, 2011 and 2010, there were no impairments on petroleum interests.

(a) Security

At December 31 2011 and 2010, all of the assets of BPAL are pledged as security for the credit facilities (see note 16).

(b) The Company reached an agreement with Albpetrol, to accelerate the takeover of production and royalty payments thereon for all remaining Albpetrol active well production and also expansion of the project area and development plan to include all of the contract area of the Patos-Marinza oilfield concession. The agreement was signed on March 31, 2011, however is subject to government and regulatory approvals.  Upon receipt of the required approvals, the Company will pay $34 million to Albpetrol under the terms of the agreement.  The Company will become the sole operator and Albpetrol will cease to conduct all petroleum operations in the Patos-Marinza oilfield and contract area.

11. DEFERRED FINANCING COSTS

($000s)							Total
Cost
Balance at January 1, 2010						$	17,709
	Exchange differences						933
	Additions						211
Balance at December 31, 2010							18,853
	Exchange differences						(418)
	Additions						30
	Transfer to long-term debt (note 16)						(18,465)
Balance at December 31, 2011						$	-

Accumulated amortization
Balance at January 1, 2010								$	1,885
	Exchange differences								199
	Amortization								2,789
Balance at December 31, 2010									4,873
	Exchange differences								(190)
	Amortization								734
	Accretion								2,555
	Transfer to long-term debt (note 16)								(7,972)
Balance at December 31, 2011								$	-

($000s)																		Total
Carrying amounts
	At January 1, 2010																$	15,824
	At December 31, 2010																$	13,980
	At December 31, 2011																$	-

Deferred financing costs pertaining to the Company's revolving loans were amortized over the life of the facilities.  These costs were netted against the corresponding long-term debt when the debt was drawn.  The debt is being accreted up to its face value using the effective interest rate method.

12. CASH AND CASH EQUIVALENTS

($000s)		2011		2010
Cash	$	8,633	$	862
Fixed income investments		40,380		105,757
	$	49,013	$	106,619

13. SHARE CAPITAL

At December 31, 2011 and December 31, 2010, the Company was authorized to issue an unlimited number of common shares with no par value.

On July 15, 2010, the Company completed a prospectus offering with a syndicate of underwriters and issued an aggregate of 12,903,228 common shares at a price of CAD$7.75 per common share on a bought deal basis, resulting in gross proceeds of $96.2 million.  Commissions and share issue costs were $4.3 million.

14. EARNINGS PER SHARE

The following table summarizes the calculation of basic and diluted weighted average number of common shares:

						2011		2010
Weighted-average number of common shares outstanding -  basic						247,148,449		236,726,203
	Dilutive effect of stock options					5,176,657		6,975,414
	Dilutive effect of warrants					3,002,497		3,294,975
Weighted-average number of common shares outstanding - diluted						255,327,603		246,996,592

The average market price of the Company's shares for purposes of calculating the dilutive effect of share options was based on quoted market prices for the year that the options were outstanding. Excluded from diluted earnings per share is the effect of 6,904,999 options for the year ended December 31, 2011 (480,000 options for 2010), as their effect is anti-dilutive.

15. WARRANTS

A summary of the changes in warrants is presented below:

		Number of  Warrants					Weighted Average Exercise Price (CAD$)
Outstanding, January 1, 2010		6,140,333								$	2.42
	Transferred to share capital on exercise	(1,277,267)									2.63
Outstanding, December 31, 2010		4,863,066									2.37
	Transferred to share capital on exercise	(174,333)									2.37
Outstanding, December 31, 2011		4,688,733								$	2.37

The following table summarizes the outstanding and exercisable warrants at December 31, 2011:

Expiry Date

Number of Warrants Outstanding and Exercisable

Weighted Average Exercise Price (CAD$)

March 1, 2012

4,688,733

2.37

Subsequent to December 31, 2011, 4,672,991 warrants were exercised, resulting in proceeds of $11.1 million.  All remaining warrants expired at March 1, 2012.

16. LONG-TERM DEBT

As at December 31, 2011 the Company had credit facilities with three international banks, including Raiffeisen Bank, the European Bank for Reconstruction and Development (EBRD) and the International Finance Corporation (IFC), as summarized below:

($000s)			Facility Amount		Outstanding Amount
					2011			2010
Raiffeisen Bank
	Operating loan (a)	$	20,000	$	12,298	$		19,741
	Term loan - 2006 (b)		-		-			3,125
	Term loan - 2009 (c)		2,074		2,074			2,963
EBRD and IFC*
	Environmental term loan (d)		10,000		6,000			-
	Revolving loan - Tranche 1 (e)		50,000		50,000			-
	Revolving loan - Tranche 2 (e)		50,000		-			-
			132,074		70,372			25,829
EBRD and IFC*
	Transfer from deferred financing costs (note 11)		-		(10,493)			-
		$	132,074	$	59,879	$		25,829

* all facilities are equally funded

These facilities are secured by all of the assets of BPAL, assignment of proceeds from the Albanian domestic and export crude oil sales contracts, a pledge of the common shares of BPAL and a guarantee by the Company.  The credit facilities are subject to certain covenants requiring the maintenance of certain financial ratios, all of which were met as at December 31, 2011 and 2010.

(a) Operating loan

The operating loan consists of a one year facility, bearing interest at a rate relative to the bank's refinancing rate plus 3.5% and matures on March 31, 2012.  As at December 31, 2011, the entire operating loan has been classified as current. Subsequent to December 31, 2011, the operating loan has been approved for renewal for an additional two years.

(b) Term loan - 2006

This term loan bears interest at the bank's refinancing rate plus 4.5%. As at December 31, 2011, the entire term loan was repaid.

(c) Term loan - 2009

This term loan bears interest at the bank's refinancing rate plus 4.65% and is repayable in equal monthly installments of $74,100 ending on April 30, 2014. As at December 31, 2011, the entire facility was utilized. Of the amount outstanding, $0.9 million is classified as current and $1.2 million as long-term. Principal repayments of the term loan over the next three years are:

($000s)
2012									$	889
2013										889
2014										296
									$	2,074

(d) Environmental term loan

The $10.0 million term loan, funded equally by IFC and EBRD, is available for environmental and social programs pertinent to the Company's activities in Albania. The interest rate is based on the London Inter-Bank Offer Rate (LIBOR) plus 4.5%.   A standby fee of 0.5% is charged on the unutilized portion.  At December 31, 2011, $6.0 million of the facility was drawn. Principal repayments commence in April 2013 in bi-annual installments of $0.5 million, or pro-rata to the amounts drawn, to both IFC and EBRD, with maturity on October 15, 2017.

(e) Revolving loans

The revolving loans, funded equally by EBRD and IFC, consist of two $50.0 million tranches, of which Tranche I is fully-utilized by the Company.  Tranche II becomes available subject to mutual agreement among the Company, IFC and EBRD, when production exceeds 10,000 barrels of oil per day and the Brent oil price exceeds $62 per barrel for twenty consecutive trading days. The interest rate is based on LIBOR plus a margin of 4.5% and is reduced to LIBOR plus a margin of 4.0% if the Brent oil price exceeds $90 per barrel for sixty consecutive trading dates. A standby fee of 2.0% is charged on any unutilized Tranche I portion and Tranche II portion, when it becomes available.  At December 31, 2011, Tranche I has been drawn down by $50.0 million of which the entire amount is classified as long-term.  For each of Tranche I and Tranche II, the amounts decline to $16.5 million on October 15, 2013, $8.3 million on October 14, 2014 with final repayment due on October 15, 2015. Principal repayments of the revolving loans over the next four years are:

($000s)
2012					$	-
2013						33,500
2014						8,250
2015						8,250
					$	50,000

17. SHARE-BASED PAYMENTS

The Company has established a "rolling" stock option plan. The number of shares reserved for issuance may not exceed 10% of the total number of issued and outstanding shares and, to any one optionee, may not exceed 5% of the issued and outstanding shares on a yearly basis or 2% if the optionee is engaged in investor relations activities or is a consultant.  The exercise price of each option shall not be less than the market price of the Company's stock at the date of grant. Under the terms of the stock option plan, the exercise of stock options will be settled by the issuance of shares of the Company.

Options issued vest one-third immediately (after three to six months following the date of the grant for new employees), one-third after one year following the date of the grant, and one-third after two years following the grant date.  Options issued expire five years following the date of the grant.

A summary of the changes in stock options is presented below:

			Number of  Options	Weighted Average Exercise Price (CAD$)
Outstanding, January 1, 2010			12,830,002			$	2.39
	Granted		4,140,000				6.71
	Exercised		(2,342,330)				2.35
	Forfeited		(113,168)				4.57
Outstanding, December 31, 2010			14,514,504				3.61
	Granted		8,757,500				7.34
	Exercised		(2,728,446)				1.93
	Forfeited		(288,335)				8.97
Outstanding, December 31, 2011			20,255,223			$	5.37
Exercisable, December 31, 2011			13,181,853			$	4.41

The range of exercise prices of the outstanding options is a follows:

Range of Exercise Price (CAD$)		Number of Options		Weighted Average Exercise Price (CAD$)		Weighted Average Remaining Contractual Life (years)
	1.01 - 2.00	4,746,889	$		1.64	1.89
	2.01 -  3.00	563,334			2.37	1.09
	3.01 - 4.00	245,000			3.59	4.11
	4.01 - 5.00	4,460,000			4.64	3.14
	5.01 - 8.00	4,203,334			6.31	3.23
	8.01 - 10.00	6,036,666			8.55	4.03
		20,255,223	$		5.37	3.09

The weighted average share price at the dates of exercise for stock options exercised during the year ended December 31, 2011 was CAD$8.38 (2010 - CAD$7.29).

Using the fair value method for share-based payments, the Company calculated share-based payments for the year ended December 31, 2011 as $24.5 million (2010 - $14.5 million) for the stock options granted to officers, directors, employees and service providers. Of these amounts, $11.0 million (2010 - $7.9 million) was charged to earnings and $13.5 million (2010 - $6.6 million) was capitalized.

The weighted average fair market value per option granted during the years ended December 31, 2011 and 2010 and the weighted average assumptions used in the Black-Scholes option pricing model in their determination were as follows:

					2011		2010
Fair value per option (CAD$)					3.19		3.96
Risk-free interest rate (%)					2.29		2.66
Forfeiture rate (%)					5		5
Volatility (%)					46		70
Expected life (years)					5		5

18. SEGMENTED INFORMATION

The Company defines its reportable segments based on geographic locations.

Year ended December 31, 2011 ($000s)						Albania			Canada		Total
		Revenues		$		339,918	$		-	$	339,918
		Royalties				(63,941)			-		(63,941)
						275,977			-		275,977
		Unrealized loss on financial commodity contracts				-			(2,904)		(2,904)
						275,977			(2,904)		273,073
		Operating expenses				60,864			-		60,864
		Sales and transportation expenses				45,460			-		45,460
		General and administrative expenses				7,792			5,981		13,773
		Depletion and depreciation				40,116			251		40,367
		Share-based payments				4,529			6,512		11,041
						158,761			12,744		171,505
						117,216			(15,648)		101,568
		Net finance expense				1,943			4,280		6,223
		Income (loss) before income tax				115,273			(19,928)		95,345
		Deferred income tax expense				(59,349)			-		(59,349)
		Net income (loss) for the year				55,924			(19,928)		35,996
		Other comprehensive income
			Currency translation adjustment			-			315		315
		Comprehensive income (loss) for the year		$		55,924	$		(19,613)	$	36,311
		Assets, December 31, 2011		$		614,830	$		46,386	$	661,216
		Liabilities, December 31, 2011		$		200,360	$		47,944	$	248,304
		Additions to PP&E		$		241,902	$		852	$	242,754

Year ended December 31, 2010 ($000s)						Albania			Canada				Total
		Revenues				$		170,376	$		-	$	170,376
		Royalties						(33,682)			-		(33,682)
								136,694			-		136,694
		Operating expenses						36,744			-		36,744
		Sales and transportation expenses						18,847			-		18,847
		General and administrative expenses						6,020			4,530		10,550
		Depletion and depreciation						22,352			159		22,511
		Share-based payments						2,247			5,653		7,900
								86,210			10,342		96,552
								50,484			(10,342)		40,142
		Net finance expense						1,536			3,333		4,869
		Income (loss) before income tax						48,948			(13,675)		35,273
		Deferred income tax expense						(24,748)			-		(24,748)
		Net income (loss) for the year						24,200			(13,675)		10,525
		Other comprehensive income
			Currency translation adjustment					-			6,094		6,094
		Comprehensive income (loss) for the year				$		24,200	$		(7,581)	$	16,619
		Assets, December 31, 2010				$		356,132	$		109,466	$	465,598
		Liabilities, December 31, 2010				$		117,548	$		1,783	$	119,331
		Additions to PP&E				$		119,557	$		160	$	119,717

Revenues by geographical region are as follows:

($000s)				2011		2010
Albania- domestic			$	68,235	$	23,942
Albania- export				271,683		146,434
			$	339,918	$	170,376

For the year ended December 31, 2011, revenues of $336.0 million (2010 - $167.3 million), were derived from six customers (2010 - five customers) who individually amounted to over 10% or more of the Company's revenues.

19. DECOMMISSIONING OBLIGATION

($000s)			2011				2010
Balance, beginning of year				$	6,622	$		4,796
			Incurred		3,854			1,994
			Revisions		2,625			(470)
			Accretion		460			302
Balance, end of year				$	13,561	$		6,622

The Company's decommissioning obligation results from its ownership interest in oil assets including well sites and gathering systems.  The total decommissioning obligation is estimated based on the Company's net ownership interest in all wells and facilities, estimated costs to reclaim and abandon these wells and facilities and the estimated timing of the costs to be incurred in future years. In Albania, the Company estimated the total undiscounted amount required to settle the decommissioning obligation at December 31, 2011 is $58.5 million (2010 - $30.9 million). This obligation will be settled at the end of the Company's 25 year license of which 19 years are remaining. The liability has been discounted using a risk-free interest rate of 8% (2010 - 8%) as at December 31, 2011.

20. INVENTORY

($000s)				2011				2010
Crude oil					$	8,081	$		3,050
Diluent						4,320			711
Diesel and other						2,011			438
					$	14,412	$		4,199

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.

21. RESTRICTED CASH

The Company has secured a $5.0 million (2010 - nil) bank guarantee for certain capital projects in Block "F".  As at December 31, 2011, the Company has incurred $1.5 million towards these projects. The Company has also secured nil (2010 - $1.5 million) for certain capital projects in the Kuçova oilfield.  As at December 31, 2011, the full amount had been incurred.

22. COMMITMENTS

The Company leases office premises, of which the minimum lease payments are payable as follows:

($000s)			Albania			Canada			Total
2012		$		550	$		507	$	1,057
2013				350			507		857
2014				346			42		388
2015				346			-		346
2016				346			-		346
2017 and after				1,210			-		1,210
		$		3,148	$		1,056	$	4,204

The Company has debt repayment commitments as disclosed in note 16.

23. RECONCILIATION FROM CANADIAN GAAP TO IFRS

The Company's accounting policies under IFRS differ from those followed under Canadian GAAP.  These accounting policies have been applied for the year ended December 31, 2011, as well as to the opening statement of financial position on the transition date, January 1, 2010, and for the year ended December 31, 2010.

The adjustments arising from the application of IFRS to amounts on the statement of financial position on the transition date and on transactions prior to that date, were recognized as an adjustment to the Company's opening deficit on the statement of financial position when appropriate.

On transition to IFRS on January 1, 2010, Bankers used certain exemptions allowed under IFRS 1 "First Time Adoption of IFRS".

IFRS 1 allows an entity that used full cost accounting under its previous GAAP to elect, at the time of adoption to IFRS, to measure oil and gas assets in the development and production phases by allocating the amount determined under the entity's previous GAAP for those assets to the underlying assets pro rata using reserve volumes or reserve values as of that date.  Bankers used reserve values as at January 1, 2010 to allocate the cost of development and production assets to CGU's.

As Bankers elected the oil and gas assets IFRS 1 exemption, the asset retirement obligation (ARO) exemption available to full cost entities was also elected.  This exemption allows for the re-measurement of ARO on IFRS transition with the offset to retained earnings.

Bankers has elected the IFRS 1 optional exemption that allows an entity to use the IFRS rules for business combinations on a prospective basis rather than re-stating all business combinations.  In respect of acquisitions prior to January 1, 2010, any goodwill represents the amount recognized under Canadian GAAP.

Bankers has elected the IFRS 1 exemption that allows the Company an exemption on IFRS 2 "Share-Based Payments" to equity instruments which vested and settled before the Company's transition date to IFRS.

Bankers has elected the IFRS 1 exemption that allows the Company an exemption on IAS 21 "The Effects of Change in Foreign Exchange Rates".  The cumulative translation differences for all foreign operations are deemed to be zero at the date of transition to IFRS. Any retrospective translation differences are recognized in opening retained earnings.

Reconciliation of the statement of financial position from Canadian GAAP to IFRS as at the date of IFRS transition - January 1, 2010

($000s)			Note			Canadian GAAP			Effect of transition to IFRS			IFRS
ASSETS
Current assets
	Cash and cash equivalents				$		59,495	$		-	$		59,495
	Short-term investments						7,275			-			7,275
	Restricted cash						1,500			-			1,500
	Accounts receivable						23,358			-			23,358
	Inventory						2,031			-			2,031
	Deposits and prepaid expenses						5,899			-			5,899
							99,558			-			99,558
Non-current assets
	Note receivable						2,749			-			2,749
	Deferred financing costs		f				14,383			1,441			15,824
	Property, plant and equipment		a,f				188,130			(206)			187,924
					$		304,820	$		1,235	$		306,055
LIABILITIES
Current liabilities
	Accounts payable and accrued liabilities					$	19,505	$		-	$		19,505
	Current portion of long-term debt						4,639			-			4,639
							24,144			-			24,144
Non-current liabilities
	Long-term debt						23,446			-			23,446
	Decommissioning obligation		b				3,856			940			4,796
	Deferred tax liabilities		g				39,414			(522)			38,892
							90,860			418			91,278
SHAREHOLDERS' EQUITY
Share capital							206,058			-			206,058
Warrants							1,739			-			1,739
Contributed surplus			c				16,812			(369)			16,443
Deficit							(10,649)			1,186			(9,463)
							213,960			817			214,777
					$		304,820	$		1,235	$		306,055

Reconciliation of the statement of financial position from Canadian GAAP to IFRS as at the end of the last reporting year under Canadian GAAP - December 31, 2010

($000s)			Note			Canadian GAAP		Effect of transition to IFRS		IFRS
ASSETS
Current assets
	Cash and cash equivalents			$		106,619	$	-	$	106,619
	Restricted cash					1,500		-		1,500
	Accounts receivable					29,233		-		29,233
	Inventory					4,199		-		4,199
	Deposits and prepaid expenses					16,624		-		16,624
						158,175		-		158,175
Non-current assets
	Deferred financing costs		f			11,805		2,175		13,980
	Property, plant and equipment		b,d,e,f,g			297,434		(3,991)		293,443
				$		467,414	$	(1,816)	$	465,598
LIABILITIES
Current liabilities
	Accounts payable and accrued liabilities			$		23,241	$	-	$	23,241
	Current portion of long-term debt					4,014		-		4,014
						27,255		-		27,255
Non-current liabilities
	Long-term debt					21,815		-		21,815
	Decommissioning obligation		b			5,496		1,126		6,622
	Deferred tax liabilities		g			69,541		(5,902)		63,639
						124,107		(4,776)		119,331
SHAREHOLDERS' EQUITY
Share capital						309,379		-		309,379
Warrants						1,597		-		1,597
Contributed surplus			c			28,715		(580)		28,135
Accumulated other comprehensive income			f			-		6,094		6,094
Retained earnings (deficit)						3,616		(2,554)		1,062
						343,307		2,960		346,267
				$		467,414	$	(1,816)	$	465,598

Reconciliation of the statement of comprehensive income for the year ended December 31, 2010

($000s)				Note			Canadian GAAP		Effect of transition to IFRS			IFRS
Revenues						$	170,376	$	-	$		170,376
Royalties							(33,682)		-			(33,682)
							136,694		-			136,694
Operating expenses							36,744		-			36,744
Sales and transportation expenses							18,847		-			18,847
General and administrative expenses				e			8,255		2,295			10,550
Depletion and depreciation				d,f			27,091		(4,580)			22,511
Share-based payments				c			8,111		(211)			7,900
							99,048		(2,496)			96,552
Finance income
	Interest income						732		-			732
	Foreign exchange gain			f			5,225		(5,154)			71
							5,957		(5,154)			803
Finance expense
	Interest and bank charges						1,160		-			1,160
	Amortization of deferred financing costs						2,789		-			2,789
	Interest on long-term debt						1,421		-			1,421
	Accretion			b			425		(123)			302
							5,795		(123)			5,672
Net finance income (expense)							162		(5,031)			(4,869)
Income before income tax							37,808		(2,535)			35,273
Deferred income tax expense				g			(23,543)		(1,205)			(24,748)
Net income for the year							14,265		(3,740)			10,525
Other comprehensive income
	Currency translation adjustment			f			-		6,094			6,094
Comprehensive income for the year						$	14,265	$	2,354	$		16,619

Notes to the reconciliations

The reconciling items between Canadian GAAP and IFRS presentation have no significant effect on the cash flows generated.  Therefore, a reconciliation of cash flows has not been presented above.

(a) IFRS 1 election for full cost oil and gas entities

The use of the IFRS 1 election for full cost oil and gas entities did not have a material impact on the statement of financial position at January 1, 2010.

Pre-exploration and evaluation expenditures of $0.1 million have been written off with a corresponding change to deficit at January 1, 2010.

(b) Decommissioning obligation

Under Canadian GAAP, ARO were discounted at a credit-adjusted risk-free rate of 10%.  Under IFRS, the estimated cash flow to abandon and remediate the wells and facilities has been risk adjusted therefore the provision is discounted at a risk-free rate in effect at the end of each reporting period.  The change in the decommissioning obligation each period as a result of changes in the discount rate will result in an offsetting charge to PP&E.  Upon transition to IFRS, the impact of this change was a $0.9 million increase in the decommissioning obligation with a corresponding increase to the deficit on the statement of financial position.

As a result of the change in discount rate, the decommissioning obligation accretion expense decreased by $0.1 million during the year ended December 31, 2010, due to the lower discount rate.

Under IFRS a separate line item is required in the statement of comprehensive income for finance costs.  The items under previous GAAP that were reclassified to finance expense were interest and bank charges, net foreign exchange loss, accretion of decommissioning obligation and amortization of deferred financing costs.

(c) Share-based payments

Under Canadian GAAP, the Company recognized an expense related to their share-based payments on a graded method of expense and did not incorporate a forfeiture rate at the grant date. Under IFRS, the Company is required to recognize the expense over the individual vesting periods for the graded vesting of awards and estimate a forfeiture rate at the date of grant and update it throughout the vesting period.  The impact on transition was a decrease in contributed surplus of $0.4 million with the offset recorded against deficit.

For the year ended December 31, 2010, incorporation of a forfeiture rate resulted in a decrease to share-based payments of $0.2 million.

(d) Depletion policy

Upon transition to IFRS, the Company adopted a policy of depleting its oil properties on a unit of production basis over proved plus probable reserves. The depletion policy under Canadian GAAP was based on units of production over proved reserves. In addition, depletion was calculated on the Albanian consolidated cost centre under Canadian GAAP.  IFRS requires depletion and depreciation to be calculated based on individual components, separately.  Accordingly, under IFRS, major workover expenditures have been depreciated on a straight-line basis over an estimated useful life of 5 years, whereas under Canadian GAAP, these expenditures were depleted with the oil properties on a unit-of-production basis over total proved reserves.

There was no impact of this difference on adoption of IFRS at January 1, 2010 as a result of the IFRS 1 election as discussed above.

For the year ended December 31, 2010, depletion and depreciation was reduced by $4.6 million with a corresponding change to PP&E.

(e) Capitalized costs

Under IFRS, employee costs included in general and administrative charges and share-based payments are capitalized to the extent they are directly attributable to PP&E and E&E.  The Company has adjusted its capitalization policy to comply with IFRS.  For the year ended December 31, 2010, $2.3 million of such costs are expensed under IFRS that were previously capitalized under previous Canadian GAAP.

(f) Foreign currency translation

IFRS requires that the functional currency of each entity in a consolidated group be determined separately based on the currency of the primary economic environment in which the entity operates.  A list of primary and secondary indicators is used under IFRS in this determination and these differ in content and emphasis to a certain degree from those factors under Canadian GAAP.  The parent company operated with US dollar as functional currency under Canadian GAAP.  The Company re-assessed the determination of the functional currency for the parent company and determined the Canadian dollar as the functional currency for this entity under IFRS.  The impact of the change in functional currency was an adjustment to deferred financing costs, property, plant and equipment and retained earnings.  The adjustment to retained earnings at the date of transition was $1.3 million (using the optional IFRS 1 exemption discussed earlier).  For the year ended December 31, 2010, the currency translation adjustment was other comprehensive income of $6.1 million.

(g) Deferred income taxes

The adjustment to deferred income taxes on transition relates to the opening adjustment to the decommissioning obligation and pre-exploration and evaluation costs.  The deferred income tax impact of the opening adjustment was a reduction in deferred tax liability of $0.5 million with the corresponding change recorded in deficit.

Under IFRS, the acquisition of an asset other than in a business combination does not give rise to any deferred income taxes based on the initial recognition exemption.  Under Canadian GAAP, any related deferred income taxes were added to the cost of the asset.  Accordingly, deferred income taxes recorded on capitalized share-based payments under Canadian GAAP have been adjusted by approximately $6.6 million for the year ended December 31, 2010.

For the year ended December 31, 2010, deferred income tax expense increased by $1.2 million as a result of all related reconciling items between Canadian GAAP and IFRS presentation.

 

 

Abby Badwi, President and Chief Executive Officer, [phone]
Doug Urch, Executive VP, Finance and Chief Financial Officer, [phone]
Mark Hodgson, VP, Business Development, [phone]

Email: [email protected]
Website: www.bankerspetroleum.com

AIM NOMAD: 
Canaccord Genuity Limited
Henry Fitzgerald-O'Connor
[phone]

AIM JOINT BROKERS:

Canaccord Genuity Limited
Ryan Gaffney/ Henry Fitzgerald-O'Connor
[phone]

Macquarie Capital Advisors
Ben Colegrave/Paul Connolly
[phone]