Bankers Petroleum Announces 2011 Financial Results
20.03.2012 | PR Newswire
33% increase in Production and doubles Cash Flow to $148 million
CALGARY, March 20, 2012 /PRNewswire/ - Bankers Petroleum Ltd. ('Bankers' or the 'Company')
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 Kucova 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 Kucova 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 Kucova 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 Kucova 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
($000s, except as noted) Yearended December31
Results at a Glance 2011 2010 2009(1)
Financial
Oil revenue 339,918 170,376 86,614
Net operating income 169,653 81,103 31,496
Net income (loss) 35,996 10,525 (150)
Per share - basic ($) 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 242,754 119,717 38,324
equipment
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
December31
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 Kucova 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 Kucova 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 Kucova 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 First Second Third Fourth
as noted) Quarter Quarter Quarter 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 11,597 10.83 14,637 13.24 17,328 13.78 17,302 14.04 60,864 13.04
expenses
Sales and 7,550 7.05 10,241 9.26 12,967 10.31 14,702 11.93 45,460 9.74
transportation
Net operating 39,834 37.22 47,244 42.72 44,898 35.71 37,677 30.56 169,653 36.36
income
2010
($000s, except First Second Third Fourth Year
as noted) Quarter Quarter Quarter Quarter
$/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 7,925 10.63 8,892 9.94 9,401 10.40 10,526 10.98 36,744 10.49
expenses
Sales and 4,395 5.90 4,535 5.07 4,804 5.31 5,113 5.33 18,847 5.38
transportation
Net operating 15,639 20.98 20,353 22.76 19,646 21.74 25,465 26.55 81,103 23.15
income
2011
($000s, except First Quarter Second Third Quarter Fourth
as noted) Quarter Quarter Year
Financial
Funds generated 29,948 43,220 42,099 32,673 147,940
from operations
Net income 11,219 10,800 13,696 281 35,996
Adjusted 12,620 11,415 8,698 6,167 38,900
earnings(1)
Basic earnings 0.046 0.044 0.055 0.001 0.146
per share ($)
General and 2,858 3,580 3,536 3,799 13,773
administrative
Total assets 522,476 565,340 612,348 661,216 661,216
Capital 51,930 69,388 65,147 56,289 242,754
expenditures
Bank loans 20,416 33,769 40,348 70,372 70,372
2010
($000s, except First Quarter Second Third Quarter Fourth Year
as noted) Quarter Quarter
Financial
Funds generated 13,289 18,254 16,036 23,292 70,871
from operations
Net income (363) 3,300 2,958 4,630 10,525
(loss)
Basic earnings (0.002) 0.014 0.012 0.019 0.044
(loss) per
share ($)
General and 2,456 2,327 2,462 3,305 10,550
administrative
Total assets 329,036 337,007 442,345 465,598 465,598
Capital 26,170 28,724 27,456 37,367 119,717
expenditures
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. (Kucova 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 $6.18/bbl on a 3P basis.
Gross Oil Reserves- Using Forecast Prices (MMbbls)
2011 2010
Patos- Total
Marinza Kucova Albania Total Albania %
Proved
Developed Producing 25.8 - 25.8 17.3 49
Developed Non-Producing - - - - -
Undeveloped 143.4 3.2 146.6 102.9 42
Total Proved 169.2 3.2 172.4 120.2 43
Probable 87.1 7.6 94.7 117.4 (19)
Total Proved Plus 256.3 10.8 267.1 237.6 12
Probable
Possible 138.9 20.3 159.2 189.0 (16)
Total Proved, Probable & 395.2 31.1 426.3 426.6 -
Possible
Net Present Value at 10% - After Tax Using Forecast Prices ($millions)
2011 2010
Patos- Total
Marinza Kucova 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 & 3,225 4
Possible 469 3,694 3,552
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 Kucova 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 Kucova 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
Kucova 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:
January1,2010
Effect
of
Canadian transition
($000s) GAAP to IFRS IFRS
Current assets $ 99,558 $ - $ 99,558
Non-current 205,262 1,235
assets 206,497
Total assets $ 304,820 $ 1,235 $ 306,055
Current 24,144 -
liabilities $ $ $ 24,144
Non-current 66,716 418
liabilities 67,134
Shareholders' 213,960 817
equity 214,777
Total 304,820 1,235
liabilities
andshareholders'
equity $ $ $ 306,055
December31, 2010
Effect of
Canadian transition
($000s) GAAP toIFRS IFRS
Current assets $ 158,175 $ - $ 158,175
Non-current 309,239
assets (1,816) 307,423
Total assets $ 467,414 $ (1,816) $ 465,598
Current 27,255
liabilities $ $ - $ 27,255
Non-current 96,852
liabilities (4,776) 92,076
Shareholders' 343,307
equity 2,960 346,267
Total 467,414
liabilities
and
shareholders'
equity $ $ (1,816) $ 465,598
The following table summarizes the statement of comprehensive income for the year ended December 31, 2010:
ForYear EndedDecember31, 2010
Effect of
Canadian transition
($000s) GAAP 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 Kucova 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 STATEMENTSOF COMPREHENSIVEINCOME
FORTHE YEARS ENDED DECEMBER 31
(Expressed in thousands of US dollars, exceptper 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
pershare 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 STATEMENTSOF FINANCIALPOSITION
(Expressed inthousands of US dollars)
ASSETS
December January
December31 31 1
Note 2011 2010 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-currentassets
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
Currentliabilities
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.
BANKERSPETROLEUM 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
cashequivalents (57,606) 47,124
Cash and cash
equivalents,
beginning of year 106,619 59,495
Cash and cash
equivalents, end
ofyear 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.
BANKERSPETROLEUM LTD.
CONSOLIDATEDSTATEMENT OFCHANGESINEQUITY
(Expressed in thousands ofUS dollars, exceptnumberofcommon shares)
Accumulated
Number of other Retained
common Share Contributed comprehensive earnings
Note shares capital Warrants surplus income (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 Kucova 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;
Non-monetary assets and liabilities are translated to
(ii) 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 Kucova 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
Quoted
prices
in Significant
active other Significant
December markets observable unobservable
31, 2011 Carrying Fair (level inputs inputs
($000s) amount value 1) (level 2) (level 3)
Financial
assets
Fair
value of
financial
commodity
contracts $ 3,684 $ 3,684 $ - $ 3,684 $ -
Fair value measurements using
Quoted
prices
in Significant
active other Significant
December markets observable unobservable
31, 2010 Carrying Fair (level inputs inputs
($000s) amount value 1) (level 2) (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 30-60 61- 90 Over 90
($000s) Current days days 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
Over
2010 30-60 61- 90 90
($000s) Current days days 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:
2015
Carrying and
($000s) Amount 2012 2013 2014 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 13,137 1,052 12,927 69,729 694 70,115
cash
equivalents
Accounts 181 - 178 215 - 216
receivable
Accounts (1,861) (3,899,416) (38,824) (1,504) (1,822,324) (19,262)
payable and
accrued
liabilities
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 22,082 (2,946)
liabilities
$ (15,743) $ (21,714)
Investing activities
Change in current liabilities
Accounts payable and accrued $ 6,786 $ 6,682
liabilities
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)
Equipment,
Petroleum Furniture
($000s) Interests and Fixtures Total
Costor 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 anddepreciation
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
Equipment,
Petroleum Furniture
($000s) Interests and Fixtures Total
Net book value
At January 1, $ 185,778 $ 2,146 $ 187,924
2010
At December 31, $ 290,088 $ 3,355 $ 293,443
2010
At December 31, $ 509,166 $ 6,472 $ 515,638
2011
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 Kucova 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 $4.3 million.
14. EARNINGS PER SHARE
The following table summarizes the calculation of basic and diluted weighted average number of common shares:
2011 2010
Weighted-average number of common shares 247,148,449 236,726,203
outstanding - basic
Dilutive effect of 5,176,657 6,975,414
stock options
Dilutive effect of 3,002,497 3,294,975
warrants
Weighted-average number of common shares 255,327,603 246,996,592
outstanding - diluted
The average market price of the Company's shares for purposes of calculating the dilutive effect of share options was based on quoted market prices for the year that the options were outstanding. Excluded from diluted earnings per share is the effect of 6,904,999 options for the year ended December 31, 2011 (480,000 options for 2010), as their effect is anti-dilutive.
15. WARRANTS
A summary of the changes in warrants is presented below:
Number of Weighted Average Exercise
Warrants Price (CAD$)
Outstanding, January 1, 6,140,333
2010 $ 2.42
Transferred to share (1,277,267)
capital on exercise 2.63
Outstanding, December 31, 4,863,066
2010 2.37
Transferred to share (174,333)
capital on exercise 2.37
Outstanding, December 31, 4,688,733
2011 $ 2.37
The following table summarizes the outstanding and exercisable warrants at December 31, 2011:
Number of Warrants Weighted Average
Outstanding and Exercise
Expiry Date Exercisable 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:
Facility
($000s) 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 - (10,493) -
costs (note 11)
$ 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:
Weighted Average
Range of Exercise Remaining
Price Number of Weighted Average Contractual Life
(CAD$) Options Exercise Price (CAD$) (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 endedDecember31,2011($000s) Albania Canada Total
Revenues $ 339,918 $ - $ 339,918
Royalties (63,941) - (63,941)
275,977 - 275,977
Unrealized loss on financial - (2,904) (2,904)
commodity contracts
275,977 (2,904) 273,073
Operating expenses 60,864 - 60,864
Sales and transportation expenses 45,460 - 45,460
General and administrative 7,792 5,981 13,773
expenses
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 $ 55,924 $ (19,613) $ 36,311
the year
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
Yearended December 31, 2010 Albania Canada Total
($000s)
Revenues $ 170,376 $ - $ 170,376
Royalties (33,682) - (33,682)
136,694 - 136,694
Operating expenses 36,744 - 36,744
Sales and transportation 18,847 - 18,847
expenses
General and 6,020 4,530 10,550
administrative expenses
Depletion and 22,352 159 22,511
depreciation
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 48,948 (13,675) 35,273
income tax
Deferred income tax (24,748) - (24,748)
expense
Net income (loss) for the 24,200 (13,675) 10,525
year
Other comprehensive
income
Currency translation - 6,094 6,094
adjustment
Comprehensive income $ 24,200 $ (7,581) $ 16,619
(loss) for the year
Assets, December 31, 2010 $ 356,132 $ 109,466 $ 465,598
Liabilities, December 31, $ 117,548 $ 1,783 $ 119,331
2010
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 Kucova 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
Effect of
Canadian transitionto
($000s) Note GAAP IFRS IFRS
ASSETS
Current assets
Cash and cash $ 59,495 $ - 59,495
equivalents $
Short-term 7,275 - 7,275
investments
Restricted cash 1,500 - 1,500
Accounts 23,358 - 23,358
receivable
Inventory 2,031 - 2,031
Deposits and 5,899 - 5,899
prepaid
expenses
99,558 - 99,558
Non-current assets
Note receivable 2,749 - 2,749
Deferred 14,383 1,441 15,824
financing costs f
Property, plant 188,130 (206) 187,924
and equipment a,f
$ 304,820 $ 1,235 $ 306,055
LIABILITIES
Current liabilities
Accounts $ 19,505 $ - 19,505
payable and $
accrued
liabilities
Current portion 4,639 - 4,639
of long-term
debt
24,144 - 24,144
Non-current liabilities
Long-term debt 23,446 - 23,446
Decommissioning 3,856 940 4,796
obligation b
Deferred tax 39,414 (522) 38,892
liabilities g
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
Effect of
transition
Canadian to
($000s) Note GAAP IFRS IFRS
ASSETS
Current assets
Cash and cash $ 106,619 $ - $ 106,619
equivalents
Restricted cash 1,500 - 1,500
Accounts 29,233 - 29,233
receivable
Inventory 4,199 - 4,199
Deposits and 16,624 - 16,624
prepaid
expenses
158,175 - 158,175
Non-current assets
Deferred f 11,805 2,175 13,980
financing costs
Property, plant b,d,e,f,g 297,434 (3,991) 293,443
and equipment
$ 467,414 $ (1,816) $ 465,598
LIABILITIES
Current
liabilities
Accounts $ 23,241 $ - $ 23,241
payable and
accrued
liabilities
Current portion 4,014 - 4,014
of long-term
debt
27,255 - 27,255
Non-current
liabilities
Long-term debt 21,815 - 21,815
Decommissioning b 5,496 1,126 6,622
obligation
Deferred tax g 69,541 (5,902) 63,639
liabilities
124,107 (4,776) 119,331
SHAREHOLDERS' EQUITY
Share capital 309,379 - 309,379
Warrants 1,597 - 1,597
Contributed c 28,715 (580) 28,135
surplus
Accumulated other f - 6,094 6,094
comprehensive
income
Retained earnings 3,616 (2,554) 1,062
(deficit)
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
Effect of
Canadian transition
($000s) Note GAAP toIFRS IFRS
Revenues $ 170,376 $ - $ 170,376
Royalties (33,682) - (33,682)
136,694 - 136,694
Operating expenses 36,744 - 36,744
Sales and 18,847 - 18,847
transportation
expenses
General and e 8,255 2,295 10,550
administrative
expenses
Depletion and d,f 27,091 (4,580) 22,511
depreciation
Share-based c 8,111 (211) 7,900
payments
99,048 (2,496) 96,552
Finance income
Interest income 732 - 732
Foreign exchange f 5,225 (5,154) 71
gain
5,957 (5,154) 803
Finance expense
Interest and 1,160 - 1,160
bank charges
Amortization of 2,789 - 2,789
deferred
financing costs
Interest on 1,421 - 1,421
long-term debt
Accretion b 425 (123) 302
5,795 (123) 5,672
Net finance income 162 (5,031) (4,869)
(expense)
Income before 37,808 (2,535) 35,273
income tax
Deferred income g (23,543) (1,205) (24,748)
tax expense
Net income for the 14,265 (3,740) 10,525
year
Other
comprehensive
income
Currency f - 6,094 6,094
translation
adjustment
Comprehensive $ 14,265 $ 2,354 $ 16,619
incomefor the year
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.
Bankers Petroleum Ltd.
CONTACT: Abby Badwi, President and Chief Executive Officer, (403) 513-2694
Doug Urch, Executive VP, Finance and Chief Financial Officer, (403)
513-2691
Mark Hodgson, VP, Business Development, (403) 513-2695
Email: investorrelations@bankerspetroleum.com
Website: www.bankerspetroleum.com
AIM NOMAD:
Canaccord Genuity Limited
Henry Fitzgerald-O'Connor
+44 20 7050 6500
AIM JOINT BROKERS:
Canaccord Genuity Limited
Ryan Gaffney/ Henry Fitzgerald-O'Connor
+44 20 7050 6500
Macquarie Capital Advisors
Ben Colegrave/Paul Connolly
+44 20 3037 5639