20th Mar 2012 12:00
Bankers Petroleum Announces 2011 Financial Results
33% increase in Production and doubles Cash Flow to $148 million
CALGARY, March 20, 2012 /CNW/ - Bankers Petroleum Ltd. ("Bankers" or the "Company") 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 Companyhas focused on expanding the water disposal capacity in the Patos-Marinzaoilfield during the quarter with drilling of four water disposal wells. Threeof the four wells have finished drilling and surface facilities installation,and are being brought on injection; the fourth well will be brought on prior tothe end of the quarter. All four wells are expected to operate at fullcapacity in the second quarter and will enable the Company to gradually bringcurrently shut-in wells related to water disposal capacity, on production overthe next few weeks. Bankers intends to issue the first quarter 2012operational update on April 10, 2012.
Outlook
The Company's capital program in 2012 will be $215 million, fully funded fromprojected cash flow based on an average $90 Brent oil price. The work programand 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 Ku§ova 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 futureproduction levels from wells, future prices and netback, work plans,anticipated total oil recovery of the Patos Marinza and Ku§ova oilfieldsconstitute forward-looking information. Statements containing forward-lookinginformation express, as at the date of this news release, the Company's plans,estimates, forecasts, projections, expectations, or beliefs as to future eventsor results and are believed to be reasonable based on information currentlyavailable to the Company.Exploration for oil is a speculative business that involves a high degree ofrisk. The Company's expectations for its Albanian operations and plans aresubject to a number of risks in addition to those inherent in oil productionoperations, including: that Brent oil prices could fall resulting in reducedreturns and a change in the economics of the project; availability offinancing; delays associated with equipment procurement, equipment failure andthe lack of suitably qualified personnel; the inherent uncertainty in theestimation of reserves; exports from Albania being disrupted due to unplanneddisruptions; and changes in the political or economic environment.Production and netback forecasts are based on a number of assumptions includingthat the rate and cost of well takeovers, well reactivations and wellrecompletions of the past will continue and success rates will be similar tothose rates experienced for previous well recompletions/reactivations/development; that further wells taken over and recompleted will produce atrates similar to the average rate of production achieved from wellsrecompletions/reactivations/development in the past; continued availability ofthe necessary equipment, personnel and financial resources to sustain theCompany's planned work program; continued political and economic stability inAlbania; approval of the Addendum to the Plan of Development; the existence ofreserves as expected; the continued release by Albpetrol of areas and wellspursuant to the Plan of Development and Addendum; the absence of unplanneddisruptions; the ability of the Company to successfully drill new wells andbring production to market; and general risks inherent in oil and gasoperations.Contingent resources disclosed herein represent those quantities of petroleumestimated, as of a given date, to be potentially recoverable from knownaccumulations, using established technology or technology under development,but which are not currently considered to be commercially recoverable due toone or more contingencies. Prospective resources disclosed herein representthose quantities of petroleum estimated, as of a given date, to be potentiallyrecoverable from undiscovered accumulations, by application of futuredevelopment 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 Ku§ova 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 BankersPetroleum Ltd.'s (Bankers or the Company) operating and financial results forthe year ended December 31, 2011, compared to the preceding year, as well asinformation and expectations concerning the Company's outlook based oncurrently available information. The MD&A should be read in conjunction withthe audited consolidated financial statements for the years ended December 31,2011 and 2010, together with the notes related thereto. Additional informationrelating to Bankers, including its Annual Information Form (AIF), is on SEDARat www.sedar.com and on the Company's website at www.bankerspetroleum.com.All dollar values are expressed in US dollars, unless otherwise indicated, andthe financial results are prepared in accordance with International FinancialReporting Standards (IFRS). The adoption of IFRS has not had an impact on theCompany's operations or strategic decisions. The Company reports its heavy oilproduction 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 theyear ended December 31, 2011, including the required comparative information,have been prepared in accordance with IFRS 1 "First-Time Adoption of IFRS", asissued by the International Accounting Standards Board (IASB). Previously, theCompany prepared its annual consolidated financial statements in accordancewith Canadian generally accepted accounting principles (GAAP).Further information on the IFRS impacts is provided in the Critical AccountingPolicies and Estimates section of this MD&A, including reconciliations betweenprevious 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 revenuenet of royalties, operating and sales and transportation expenses. The Companybelieves that net operating income is a useful supplemental measure to analyzeoperating performance and provides an indication of the results generated bythe Company's principal business activities prior to the consideration of otherincome 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 asof March 16, 2012 and contains forward-looking information. Such informationis generally identified by the use of words such as "anticipate", "continue","estimate", "expect", "may", "will", "project", "should", "believe" and similarexpressions are intended to identify forward-looking statements. Statementsrelating to "reserves" or "resources" are also forward-looking statements, asthey involve the implied assessment, based on certain estimates and assumptionsthat the resources and reserves described can be profitably produced in thefuture. All such statements involve known and unknown risks, uncertainties andother factors that may cause actual results or events to differ materially fromthose anticipated in such forward-looking statements. Management believes theexpectations reflected in those forward-looking statements are reasonable butno assurance can be given that these expectations will prove to be correct andsuch forward-looking statements included in this MD&A should not be undulyrelied 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 Form51-101F1 Statement of Reserves Data and Other Oil and Gas Information (NI51-101 Report), availability of funds for capital expenditures, a consistentsuccess rate for well recompletions and drilling at Patos-Marinza oilfield,increasing production as contemplated by the Plan of Development (PoD), stablecosts, availability of equipment and personnel when required, continuingfavourable relations with Albanian governmental agencies and continuing strongdemand 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 basedon the events and circumstances that occurred during the period and hasadjusted its capital expenditure program accordingly to ensure that capitalexpenditures are funded by cash provided by operations, cash on hand and itsavailable credit.Readers are cautioned that the foregoing lists of factors are not exhaustive.The forward-looking statements contained in this MD&A are expressly qualifiedby this cautionary statement.
BUSINESS PROFILE
Bankers is a Canadian-based oil exploration and production company focused onmaximizing the value of its heavy oil assets in Albania. The Company istargeting growth in production and reserves through application of new andproven technologies by an experienced technical team. The Company generates allof the oil revenue from its operations in Albania, which is located northwestof Greece in South Eastern Europe.In Albania, Bankers operates and has the full rights to develop thePatos-Marinza and Ku§ova oilfields pursuant to License Agreements with theAlbanian National Agency for Natural Resources (AKBN) and Petroleum Agreementswith Albpetrol Sh.A (Albpetrol), the state owned oil and gas corporation. Thedevelopment and production phases became effective in March 2006 and March2011, respectively, each having a 25 year term with an option to extend at theCompany's election for further five year increments. The Patos-Marinza oilfieldis the largest onshore oilfield in continental Europe, holding approximately7.7 billion barrels of original-oil-in-place (OOIP). The Company also hasexclusive rights to exploration Block "F" (adjacent to the Patos-Marinzaoilfield), a 185,000 acre oil and gas prone exploration field.OVERVIEW & SELECTED ANNUAL INFORMATION ($000s, except as noted) Year ended December 31 Results at a Glance 2011 2010 2009 (1) Financial Oil revenue 339,918 170,376 86,614 Net operating income 169,653 81,103 31,496 Net income (loss) 35,996 10,525 (150) Per share - basic ($) 0.146 0.044 (0.001) - diluted ($) 0.141 0.043 (0.001)
Funds generated from operations 147,940 70,871 25,422 Per share - basic ($) 0.599 0.299 0.123 Additions to property, plant and 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 ($/ 111.26 79.50 61.67 barrel) December 31 2011 2010 2009 (1) Cash and deposits 54,013 108,119 68,270 Working capital 80,282 130,920 75,414 Total assets 661,216 465,598 306,055 Long-term debt 46,692 21,815 23,446 Shareholders' equity 412,679 346,267 214,777
(1) 2009 comparative figures are prepared in accordance with Canadian GAAP. Bankers increased its oil revenue, net operating income and funds generatedfrom operations during the year through its continued success with thehorizontal drilling program and ongoing well reactivations. The average oilsales 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 2011resulted 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 2011represented approximately 65% of the Brent oil price, an improvement from 61%of Brent in 2010. Oil exports represented 80% of the total revenue during theyear, compared to 85% in 2010, with the balance supplying the domestic Albanianrefineries.
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 in2010 and $214.8 million in 2009. The increase in shareholders' equity in 2011was 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 Ku§ova 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 reserveswith production growth potential. Employing its knowledge base and technicalexpertise, the Company is working to optimize its existing assets from theapplication of primary, secondary and enhanced oil recovery (EOR) extractiontechnologies, creating long-term value for shareholders. This will beaccomplished through the attainment of its main objectives: increasingproduction, 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 otherpotential petroleum opportunities in Albania to increase overall value. Thearea contains several seismically defined structures and amplitude anomaliesprospective for oil and natural gas.Throughout the year, Bankers focused on achieving its priorities andimplementing its capital programs in Albania. The Company funded its capitalprograms using funds generated from operations and existing cash. Strategicallocation of the work program and budget is designated to provide additionalrecoverable reserves at the Patos-Marinza and Ku§ova oilfields and stillachieve an appropriate growth in production.
Key Performance Indicators
Key performance indicators relate to those factors that Bankers can directlyaffect, and are indicators of the Company's ability to provide long-term valueto its shareholders, which include optimizing the cost of operations over time,improving exploration and development and increasing operational performancethrough technology and best practices. Key measurements include operatingcosts, production volumes and safety performance. These key performanceindicators are continuously reviewed and monitored.In addition, strengthening relationships with employees, governments,communities and other stakeholders are important aspects of the business forBankers. The effective management of these relationships allows the Company totap into new growth opportunities and efficiently develop operations for thefuture.CAPABILITY TO DELIVER RESULTS
Activity in the oil industry is subject to a range of external factors that aredifficult to actively manage, including commodity prices, resource demand,regulator and environmental regulations and climate conditions. Bankers givessignificant consideration to these factors and backs-up its strategy byemploying and positioning necessary resources to deliver on its goals andcommitment to increase value for shareholders. The Company focuses its capitalon opportunities that provide the potential for the best returns. Comprehensiveinsurance policies are in place to help safeguard its assets, operations andemployees. Relationships with stakeholders and key partners are carefullycultivated to assist in the Company's future development and growth. Theexperiences of management and its technical team ensure that the Company canfulfill 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 averageBrent 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 Brentoil 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 toimprovements in the commodity market. These events included expansion of thehorizontal drilling program by activating a fourth and fifth drilling rig;construction of the first phase of the crude oil sales pipeline; constructionof the Seman River bridge; construction of the third and fourth oil treatingtrains at the central treating facilities; continued environmental initiativesincluding completion of pilot area legacy pollution clean-up and technologytrials; commencement of thermal operations at the southern Patos Cyclic SteamPilot; commencement of water injection and production in Ku§ova and the overallgrowth of capital programs.The Company drilled 84 wells during 2011, including 76 horizontal productionwells, two vertical delineation wells, two cyclic steam horizontal wells andfour water disposal wells.The Company provided a $5.0 million bank guarantee for certain capital projectsin Block "F". The first Block "F" exploration location has been selected andsurface lease construction is underway with expected spud of the well in April2012.QUARTERLY SUMMARY Below is a summary of Bankers' performance over the last eight quarters. 2011 ($000s, except First Second Third Fourth Year as noted) Quarter Quarter Quarter Quarter $/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 10.49expenses Sales and 4,395 5.90 4,535 5.07 4,804 5.31 5,113 5.33 18,847 5.38transportation Net operating 15,639 20.98 20,353 22.76 19,646 21.74 25,465 26.55 81,103 23.15income 2011 ($000s, except as noted) First Second Third Fourth Quarter Quarter Quarter Quarter Year Financial Funds generated from 29,948 43,220 42,099 32,673 147,940operations Net income 11,219 10,800 13,696 281 35,996 Adjusted earnings(1) 12,620 11,415 8,698 6,167 38,900 Basic earnings per share 0.046 0.044 0.055 0.001 0.146($) General and 2,858 3,580 3,536 3,799 13,773administrative Total assets 522,476 565,340 612,348 661,216 661,216 Capital expenditures 51,930 69,388 65,147 56,289 242,754 Bank loans 20,416 33,769 40,348 70,372 70,372 2010 ($000s, except as noted) First Second Third Fourth Year Quarter Quarter Quarter Quarter Financial Funds generated from 13,289 18,254 16,036 23,292 70,871operations Net income (loss) (363) 3,300 2,958 4,630 10,525 Basic earnings (loss) per (0.002) 0.014 0.012 0.019 0.044share ($) General and 2,456 2,327 2,462 3,305 10,550administrative Total assets 329,036 337,007 442,345 465,598 465,598 Capital expenditures 26,170 28,724 27,456 37,367 119,717 Bank loans 26,418 27,330 23,887 25,829 25,829
(1) Represents net income before gain (loss) on financial commodity contracts.
DISCUSSION OF OPERATING RESULTS
Sales, Revenue and Netback
2011 2010 % Average sales (bopd) 12,784 9,597 33 Oil revenue ($000s) 339,918 170,376 100 Netback ($/barrel) Average price 72.84 48.64 50 Royalties 13.70 9.62 43 Operating expenses 13.04 10.49 24 Sales and transportation 9.74 5.38 81 Netback 36.36 23.15 57 Average sales for 2011 were 12,784 bopd, an increase of 33% from 9,597 bopd for2010. The increase in sales was due to expansion of the drilling program,continued well reactivation program and well recompletion program focused onbringing high productivity wells on stream.At the end of December 2011, the Company had approximately 280 active producingwells as compared to 250 wells at the end of 2010. This does not include allthe productive wells as several are down at any point in time for normaloperational servicing, such as pump changes, cleanouts, and stimulation. Inaddition, several infrastructure projects were being completed at the end ofthe year limiting the maximum active well count. The Company total wellinventory including wells taken-over from Albpetrol as well as new drillsincreased from 826 at the end of 2010 to 1,296 at December 31, 2011. Themajority of the additional wells were taken over in the northern region of thefield to access areas north of the river and to consolidate our operationalareas rather than for production purposes.The Company received an average $72.84/bbl (65% of Brent) for the year, anincrease of 50% from $48.64/bbl (61% of Brent) for the preceding year. Thisincrease was largely due to the increase in commodity prices during 2011. Theaverage Brent oil price for 2011 was $111.26/bbl, a 40% improvement as comparedto $79.50/bbl in 2010. Oil revenue increased by 100% to $339.9 million in 2011compared to $170.4 million in 2010 due to higher realized oil prices andincreased sales.The Company's sales averaged 13,399 bopd during the fourth quarter of 2011compared to 13,667 bopd during the preceding quarter and 10,424 bopd during thefourth quarter of 2010. The December 31, 2011 crude oil inventory levelincreased during the fourth quarter by 40,000 barrels to 241,000 barrels, as aresult of storage requirements associated with additional tanks. Fourth quartersales were slightly lower than the previous quarter due to limitations on waterdisposal capability. The Company's produced water handling capacity isexpected to increase in the second quarter of 2012 as a result of four newwater disposal wells drilled in the first quarter of 2012. Total revenues forthe fourth quarter of 2011 was $88.3 million compared to $93.7 million in thethird 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 quarterof 2011 compared to $74.48/bbl during the preceding quarter and $53.12/bblduring the same period in 2010. The Company exported 93% of its crude oilduring the fourth quarter of 2011 compared to 80% during the preceding quarterand 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 withAlbpetrol 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% royaltytax (RT) on net production. Overall royalties for the year represented 19% ofoil revenue, slightly reduced from 20% for 2010. As a percent of revenue, thevarious royalty components currently represent 8% from PEP, 1% for the ORR and10% for the RT. Fluctuations in royalty on a per barrel basis are mainly dueto 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 costsrepresented 18% of the revenue for the year, compared to 22% for the precedingyear. The improvement from 2010, as a percentage of revenue, was due toincreased sales levels and the significant increase in commodity prices. On aper active well basis, the energy costs were higher as a result of increaseddiesel, propane, and electricity costs as well as higher well servicing anddown-hole equipment costs with a greater frequency of well interventionsrequired for pump changes, clean outs, and stimulation. The personnel costsalso increased with the addition of operations staff for the higher pace ofdevelopment and larger number of active wells operating. Of the total operatingexpenses 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% ofrevenue) 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 moderateincrease in operating expenses, as a percentage of revenue, compared to thepreceding quarter was a result of increased well servicing costs during thefourth quarter. The decrease from the fourth quarter of 2010 as a percentage ofrevenue was due to the higher sales volumes and commodity prices, while the perwell costs in the fourth quarter of 2011 were higher than the same quarter in2010 with the higher frequency of well servicing associated with normaloptimization 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/bblduring the preceding quarter and $5.33/bbl in the fourth quarter of 2010. Theincrease in S&T costs compared to the previous quarter and same period in 2010was mainly due to the increased blend ratio of diluent in the sales oil and thehigher export sales. The export sales were 93% of total sales for the fourthquarter, 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 thesales oil with the development of heavier oil from the wells drilled during theyear. 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 of2010. Port fees for the fourth quarter of 2011 were $1.83/bbl, an increasefrom $1.01/bbl in the preceding quarter and $0.60/bbl for the same period in2010.
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-basedpayments compared to $7.8 million for the preceding year. These expenses weredirectly related to acquisition, exploration and development activities inAlbania.Non-cash share-based payments pertaining to stock options granted to officers,directors, employees and service providers were $24.5 million (2010 - $14.5million). Of this amount, $11.0 million (2010 - $7.9 million) was charged toearnings 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 $3.5million 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 additionalpersonnel 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 expensescorrespond to the respective production levels and the impact of capitalexpenditures relative to the depletable basis. The increase in D&D expensesreflects higher production in Albania and an increase in depletable assets,inclusive of higher future capital requirements. The Company's independentreserve evaluation, prepared in accordance with the National Instrument NI51-101, assessed proved and probable gross reserves of 267.1 million barrels atDecember 31, 2011, an increase of 12% from 237.6 million barrels at December31, 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 $7.5million ($7.56/bbl) for the same period in 2010. The increase in D&D reflectsthe higher depletion base as a result of increased future development costscombined with the increase in production during the quarter. The depletablebase at December 31, 2011 includes a provision of $1.9 billion for expectedfuture 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 forthe year ended December 31, 2011, slightly lower than 13% for 2010. Thereduction, as a percentage of revenue, was mainly due to the increase inreserve base, increase in production and commodity price.
Income Taxes
As of December 31, 2011, the Company recorded a $123.0 million deferred incometax liability, compared to $63.6 million at the end of 2010, in relation to theCompany's Albanian assets and liabilities. Deferred income tax expense for 2011was $59.3 million compared to $24.7 million for the preceding year. Theincrease in deferred income taxes from 2010 was mainly due to the increase innet income incurred in 2011 and non-deductible costs, including share-basedpayments 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 mainlydue to higher income of the Albanian segment.On a quarterly basis, the Company recorded deferred income tax expense of $10.6million compared to $20.4 million for the preceding quarter and $7.3 millionfor the same period in 2010. The change in the deferred income tax expense wasmainly 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 Albaniaat a 50% income tax rate. Bankers is presently not required to pay cash taxesin any jurisdiction. In Canada, the benefit of non-capital losses ofapproximately $33.8 million as of December 31, 2011 has not been recognized inthe financial statements.
Net Income and Funds Generated from Operations
The Company recorded net income of $36.0 million ($0.146 per share) during theyear ended December 31, 2011 and $10.5 million ($0.044 per share) for the yearended 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 December31, 2011, an increase of 109% compared to $70.9 million in 2010. The increasein funds generated from operations was mainly due to higher sales and commodityprices during the year.Funds generated from operations were $32.7 million for the fourth quarter of2011 compared to $42.1 million in the previous quarter and $23.3 million forthe same period in 2010.OIL RESERVESAnnually, the Company obtains independent reserves evaluations of its Albanianproperties by RPS Energy Canada Ltd. (Patos-Marinza oilfield) and by DeGolyerand MacNaughton Canada Ltd. (Ku§ova oilfield). At December 31, 2011, reservesincreased on a total proved (1P) and total proved plus probable (2P) basis andremained consistent on a total proved, probable and possible (3P) basis.Changes within each reserve basis are shown below. The 2011 finding anddevelopment costs for the Albanian properties represented $11.50/bbl on a 1Pbasis, $8.48/bbl on a 2P basis and $6.18/bbl on a 3P basis.
Gross Oil Reserves- Using Forecast Prices (MMbbls)
2011 2010 Patos- Total Marinza Ku§ova Albania Total Albania % Proved Developed Producing 25.8 - 25.8 17.3 49 Developed Non-Producing - - - - - Undeveloped 143.4 3.2 146.6 102.9 42 Total Proved 169.2 3.2 172.4 120.2 43 Probable 87.1 7.6 94.7 117.4 (19) Total Proved Plus Probable 256.3 10.8 267.1 237.6 12 Possible 138.9 20.3 159.2 189.0 (16)
Total Proved, Probable & Possible 395.2 31.1 426.3 426.6 -
Net Present Value at 10% - After Tax Using Forecast Prices ($millions)
2011 2010 Patos- Total Marinza Ku§ova Albania Total Albania % Proved Developed Producing 347 - 347 220 58 Developed Non-Producing - - - - - Undeveloped 647 22 669 729 (8) Total Proved 994 22 1,016 949 7 Probable 854 103 957 1,019 (6) Total Proved Plus Probable 1,848 125 1,973 1,968 - Possible 1,377 344 1,721 1,584 9
Total Proved, Probable & Possible 3,225 469 3,694 3,552 4 In the Patos-Marinza oilfield, the OOIP at the end of 2011 increased 3% to 7.7billion barrels from 7.5 billion at the end of 2010. Additionally, theCompany's independent reserves engineers assigned contingent and prospectiveresource oil estimates of 1.0 billion and 614 million barrels, respectively.This assessment is based on primary horizontal and secondary water-flooddevelopments as well as thermal development technologies being applied to areasof the Patos-Marinza field.The reserves growth in the Patos-Marinza field is primarily attributable tocontinued implementation of horizontal drilling, expansion of field developmentto enhance recovery and the upgrade of 3P into 2P reserves and 2P into 1Preserves, based on extended periods of actual well and reservoir performance.Significant additional reserves resulted from horizontal drilling in new areasof the field where no reserves had been booked in previous years, whichresulted in a direct migration of contingent resource into proved and possiblereserves. All of Patos-Marinza's 2011 reserves estimates are from primaryrecovery methods.The Company acquired the Ku§ova asset in 2008 and the OOIP resource estimate is297 million barrels. This property is currently in early stage developmentwith no Company production from the Ku§ova oilfield in 2011. The water-floodpilot started in 2011 with one injector and two producers with plans to expandthe program in 2012. Bankers expects to continue activity in this area in 2012utilizing a variety of extraction techniques that will lead to creation of adevelopment plan.The Company acquired the Block "F" asset in 2010. There are currently no oilor gas resource bookings for Block "F" in 2011. A thorough review of theavailable seismic lines including reprocessing of the lines was conducted in2011 and exploration prospect drilling on structural and stratigraphicanomalies 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 Ku§ova 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 $119.7million in the preceding year, an increase of 103%. This increase was mainlydue to the expansion of the Company's capital programs in drilling,reactivation, thermal project and other base projects, including the salespipeline construction, facility infrastructure expansion and environmentalstewardship programs in the Patos-Marinza oilfield. During the year, Bankersspent $110.2 million on the drilling program, which consisted of 76 horizontalproduction wells and 2 vertical delineation wells, compared to $69.6 million in2010 (50 horizontal wells and 2 vertical wells). Bankers spent $25.6 millionon well reactivations compared to $8.4 million in the previous year. Theincrease in well-reactivation costs was a result of additional wells attemptedfor reactivation during the year compared to the previous year. A total of 384wells were taken over from Albpetrol in 2011, compared to 199 in 2010. Thesewells are primarily for contiguous area consolidation purposes, but severalwells 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 drilledduring the year and thermal operations commenced at the southern Patos CyclicSteam Pilot in late 2011. Base program expenditures increased 197% during theyear due to the increase in facility infrastructure, environmental stewardship,pipeline and sale infrastructure and water control/disposal initiatives (fourwater disposal wells were drilled during the year).Included in property, plant and equipment as of December 31, 2011 are oilfieldequipment of $37.7 million for utilization in future drilling, reactivation andinfrastructure programs in the Patos-Marinza oilfield, as compared to $17.5million at December 31, 2010.During the fourth quarter of 2011, Bankers incurred $56.3 million in capitalexpenditures; $36.8 million on drilling operations, $3.7 million on wellreactivations and $15.6 million related to the base program. The balance of theexpenditures was incurred on the work-over program, thermal project and othermiscellaneous expenses and capitalized G&A. By comparison, in the fourthquarter 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 incurredon 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 (includingcash 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 $130.9million and long-term bank loans of $21.8 million.Bankers has credit facilities totalling $132.1 million, of which $70.4 millionwas utilized at December 31, 2011. The majority of the credit facilitiesrepresent a reserve-based long-term financing of $110.0 million from theInternational Finance Corporation and European Bank for Reconstruction andDevelopment, of which $56.0 million was drawn. The $22.1 million Raiffeisenfacility 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 wasmade 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 4.7million outstanding warrants at December 31, 2011. Subsequent to 2011year-end, approximately 3.8 million stock options were granted, approximately0.5 million stock options were exercised and approximately 4.7 million warrantswere exercised, generating proceeds of approximately $1.0 million and $11.1million, respectively. All remaining warrants expired on March 1, 2012. OnMarch 16, 2012, Bankers has approximately 24 million stock options and nilwarrants outstanding.Directors and officers of the Company represent approximately 7 percentownership in the Company, on a fully diluted basis, as of December 31, 2011 andapproximately 8 percent as of March 16, 2012. The strong ownership position ofthe directors and officers creates an alignment with shareholders and a teamthat 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 pricevolatility and its impact on cash flows, the Company entered into variousfinancial hedging agreements during the first quarter of 2011. The Companypurchased put contracts representing 4,000 bopd at $80/bbl of Dated Brent for2012, for $6.6 million. Unsettled derivative financial contracts are recordedat the date of the financial statements based on the fair value of thecontracts. Changes in fair value result from volatility in forward curves ofcommodity prices and changes in the balance of unsettled contracts betweenperiods. The fluctuations in fair values are recognized as unrealized gain andloss on financial commodity contracts. As of December 31, 2011, the fair valueof these contracts was $3.7 million.
Plan of Development
Bankers has no capital expenditure commitment for the Patos-Marinza oilfieldunder the Petroleum Agreement. Bankers annually submits a work program to AKBNwhich includes the nature and the amount of capital expenditures to be incurredduring that year. Significant deviations in this annual program from the Planof Development will be subject to AKBN approval. The Petroleum Agreementprovides that disagreements between the parties will be referred to anindependent expert whose decision will be binding. The Company has the right torelinquish a portion or all of the contract area. If only a portion of thecontract area is relinquished then the Company will continue to conductpetroleum operations on the portion it retains and the future capitalexpenditures 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 loansoutstanding with three international banks, totalling $70.4 million. Theoperating 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 millionon October 14, 2014 with final repayment due on October 15, 2015. The 2009term loan is repayable in equal monthly instalments of $74,100 ending on April30, 2014 and the environmental term loan is repayable commencing April 2013 inbi-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 thetiming of transfer of wells from Albpetrol results in production increases thatare typically higher in the second and third quarters. As new wells come onstream, there is a build-up period in production, higher sand production andhigher well servicing costs, which is typical for heavy oil wells in the firstyear of production. In addition, production levels can be affected by waterdisposal constraints, mechanical wellbore and isolation failures, increasedwater production coming from shallower and deeper zones, and a shortage of rigwork-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 reportedfinancial position, financial performance and cash flows of the Company isprovided in note 23 to the consolidated financial statements. This noteincludes reconciliations of equity and total comprehensive income forcomparative periods reported under previous GAAP to those reported for thoseperiods under IFRS. The Company's IFRS accounting policies are referred to innote 3 to the consolidated financial statements.
Accounting Policy Changes
The following discussion explains the significant difference between theCompany's previous GAAP accounting policies and those applied by the Companyunder IFRS. IFRS policies have been retrospectively and consistently appliedexcept where specific IFRS 1 optional and mandatory exemptions permitted analternative 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 payoutwill 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 jurisdictionsin which the Company operates are subject to change. As such, income taxes aresubject to measurement uncertainty. Deferred income tax assets are assessed bymanagement at the end of the reporting period to determine the likelihood thatthey will be realized from future taxable earnings.The amounts recorded for depreciation and depletion of oil and natural gasproperties are based on estimates of proved and probable reserves and futurecapital costs. The ceiling test is based on estimates of proved and probablereserves, production rates, future commodity prices, future costs and otherrelevant assumptions.
Reconciliations from Canadian GAAP to IFRS
The following tables provide a summary reconciliation of Bankers' Statement ofFinancial Position at January 1, 2010 and December 31, 2010 from GAAP to IFRS: January 1, 2010 Canadian Effect of ($000s) GAAP transition to IFRS IFRS Current assets $ 99,558 $ - $ 99,558 Non-current assets 205,262 1,235 206,497 Total assets $ 304,820 $ 1,235 $ 306,055 Current liabilities $ 24,144 $ - $ 24,144 Non-current liabilities 66,716 418 67,134 Shareholders' equity 213,960 817 214,777
Total liabilities and shareholders' 304,820 1,235
equity $ $ $ 306,055 December 31, 2010 Canadian Effect of ($000s) GAAP transition to IFRS IFRS Current assets $ 158,175 $ - $ 158,175 Non-current assets 309,239 (1,816) 307,423 Total assets $ 467,414 $ (1,816) $ 465,598 Current liabilities $ 27,255 $ - $ 27,255 Non-current liabilities 96,852 (4,776) 92,076 Shareholders' equity 343,307 2,960 346,267
Total liabilities and shareholders' 467,414
equity $ $ (1,816) $ 465,598
The following table summarizes the statement of comprehensive income for the year ended December 31, 2010:
For Year Ended December 31, 2010 Canadian Effect of ($000s) GAAP transition to IFRS IFRS Total Revenue $ 137,426 $ (732) $ 136,694 Total Expenses 99,618 (277) 99,341
Income before financing items and income tax 37,808 (455)
37,353 Financing items - (2,080) (2,080) Income before income taxes 37,808 (2,535) 35,273 Income taxes (23,543) (1,205) (24,748) Net income for the year 14,265 (3,740) 10,525 Other comprehensive income - 6,094 6,094
Comprehensive income for the year $ 14,265 $ 2,354
$ 16,619
NEW ACCOUNTING STANDARDS TO BE ADOPTED
In May 2011, the IASB issued four new standards and two amendments. Five ofthese items related to consolidation, while the remaining one addresses fairvalue measurement. All of the new standards are effective for annual periodsbeginning on or after January 1, 2013. Early adoption is permitted.IFRS 10 "Consolidated Financial Statements" introduces a new principle-baseddefinition of control, applicable to all investees to determine the scope ofconsolidation. The standard provides the framework for consolidated financialstatements 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 ownaccounting model. A "joint operation" continues to be accounted for usingproportionate consolidation, where a "joint venture" must be accounted forusing equity accounting. This differs from IAS 31, where there was the choiceto use proportionate consolidation or equity accounting for joint ventures. A"joint operation" is defined as the joint operators having rights to theassets, and obligations for the liabilities, relating to the arrangement. In a"joint venture", the joint ventures' have rights to the net assets of thearrangement, typically through their investment in a separate joint ventureentity.IFRS 12 "Disclosure of Interests in Other Entities" is a new standard, whichcombines all of the disclosure requirements for subsidiaries, associates andjoint 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", whichcovers the classification and measurement of financial assets as part of itsproject to replace IAS 39 "Financial Instruments: Recognition and Measurement."In October 2010, the requirements for classifying and measuring financialliabilities were added to IFRS 9. Under this guidance, entities have the optionto recognize financial liabilities at fair value through earnings. If thisoption is elected, entities would be required to reverse the portion of thefair value change due to a company's own credit risk out of earnings andrecognize the change in other comprehensive income. IFRS 9 is effective for theCompany on January 1, 2015. Early adoption is permitted and the standard isrequired 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 VicePresident, Finance and Chief Financial Officer (CFO) have designed, or causedto be designed under their supervision, disclosure controls and procedures (DC&P) and internal controls over financial reporting (ICOFR) as defined inNational Instrument 52-109 certification of Disclosure in Issuer's Annual andInterim Filings in order to provide reasonable assurance regarding thereliability of financial reporting and the preparation of the financialstatements for external purposes in accordance with IFRS.The DC&P have been designed to provide reasonable assurance that materialinformation relating to Bankers is made known to the CEO and CFO by others andthat information required to be disclosed by the Company in its annual filings,interim filings or other reports filed or submitted by Bankers under securitieslegislation is recorded, processed, summarized and reported within the timeperiods specified in securities legislation. The Company's CEO and CFO haveconcluded, based on their evaluation as of December 31, 2011 that the Company'sdisclosure controls and procedures are effective to provide reasonableassurance that material information related to the issuer, is made known tothem by others within the Company.The CEO and CFO are required to cause the Company to disclose any change in theCompany's ICOFR that occurred during the most recent interim period that hasmaterially affected, or is reasonably likely to materially affect, theCompany's ICOFR. No changes in ICOFR were identified during such period thathave materially affected or are reasonably likely to materially affect, theCompany's ICOFR. There were no changes to ICOFR as a result of the transitionto 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, notabsolute, assurance that the objective of the control system will be met and itshould 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 fromprojected cash flow based on an average $90 Brent oil price. The work programand 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 Ku§ova oilfield with 5 injector conversions and 13 production reactivation wells.
·Drilling of 2 exploration wells on Block "F".
·Continuing with the environmental stewardship and social initiatives in our area of operations.
BANKERS PETROLEUM LTD. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME FOR THE YEARS ENDED DECEMBER 31 (Expressed in thousands of US dollars, except per share amounts) Note 2011 2010 Revenues $ 339,918 $ 170,376 Royalties (63,941) (33,682) 275,977 136,694 Unrealized loss on financial commodity contracts 5(d) (2,904) -
273,073 136,694 Operating expenses 60,864 36,744
Sales and transportation expenses 45,460 18,847 General and administrative expenses 13,773 10,550
Depletion and depreciation 10 40,367 22,511 Share-based payments 17 11,041 7,900 171,505 96,552 101,568 40,142 Net finance expense 7 6,223 4,869 Income before income tax 95,345 35,273 Deferred income tax expense 9 (59,349) (24,748) Net income for the year 35,996 10,525 Other comprehensive income Currency translation adjustment 315 6,094 Comprehensive income for the year $ 36,311 $ 16,619
Basic earnings per share 14 $ 0.146 $ 0.044 Diluted earnings per share 14 $ 0.141 $ 0.043
The notes are an integral part of these consolidated financial statements.APPROVED BY THE BOARD"Robert Cross" Director "Eric Brown" Director BANKERS PETROLEUM LTD. CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (Expressed in thousands of US dollars) ASSETS December 31 December 31 January 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-current assets Note receivable - - 2,749 Deferred financing costs 11 - 13,980 15,824 Property, plant and equipment 10 515,638 293,443 187,924 $ 661,216 $ 465,598 $ 306,055 LIABILITIES Current liabilities Accounts payable and accrued liabilities $ 52,109 $ 23,241 $ 19,505 Current portion of long-term debt 16 13,187 4,014 4,639 65,296 27,255 24,144 Non-current liabilities Long-term debt 16 46,692 21,815 23,446 Decommissioning obligation 19 13,561 6,622 4,796 Deferred tax liabilities 9 122,988 63,639 38,892 248,537 119,331 91,278 SHAREHOLDERS' EQUITY Share capital 13 318,021 309,379 206,058 Warrants 15 1,540 1,597 1,739 Contributed surplus 49,651 28,135 16,443 Accumulated other comprehensive income 6,409 6,094 - Retained earnings (deficit) 37,058 1,062 (9,463) 412,679 346,267 214,777 $ 661,216 $ 465,598 $ 306,055 Commitments (Note 22)
The notes are an integral part of these consolidated financial statements.
BANKERS PETROLEUM LTD. CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31
(Expressed in thousands of US dollars) Note 2011 2010
Cash provided by (used in):
Operating activities Net income for the year $ 35,996 $ 10,525
Depletion and depreciation 40,367
22,511 Amortization of deferred financing costs 11 734 2,789
Accretion of long-term debt 11 2,555
-
Accretion of decommissioning
obligation 19 460 302
Unrealized foreign exchange loss 1,122
2,096 Deferred income tax expense 59,349 24,748 Share-based payments 11,041 7,900 Unrealized loss on financial commodity contracts 2,904 -
Cash premiums paid for financial
commodity contracts 5(d) (6,588) - 147,940 70,871
Change in non-cash working capital 8 (15,743)
(21,714) 132,197 49,157 Investing activities Additions to property, plant and equipment (242,754) (119,717) Restricted cash (3,500) - Change in non-cash working capital 8 6,786 6,682 (239,468) (113,035) Financing activities Issue of shares for cash 5,783 104,720 Financing costs 11 (30) (211) Increase (decrease) in long-term debt 16 44,543 (2,256) Share issue costs (167) (4,333) Note receivable - 2,749 Short-term investments - 7,275 50,129 107,944
Foreign exchange gain (loss) on
cash and cash equivalents (464) 3,058 Increase (decrease) in cash and cash equivalents (57,606) 47,124
Cash and cash equivalents, beginning of year 106,619
59,495
Cash and cash equivalents, end of year 12 $ 49,013 $
106,619 Interest paid $ 2,362 $ 2,581 Interest received $ 574 $ 787
The notes are an integral part of these consolidated financial statements.
BANKERS PETROLEUM LTD. CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (Expressed in thousands of US dollars, except number of common shares) 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 andits wholly-owned operating subsidiaries (Group) - Bankers Petroleum AlbaniaLtd. (BPAL), Bankers Petroleum International Limited (BPIL) and SherwoodInternational Petroleum Ltd (Sherwood). BPAL and Sherwood are incorporated inthe Cayman Islands and BPIL is incorporated in Jersey.The Group operates in Albanian oilfields pursuant to Petroleum Agreements withAlbpetrol Sh.A (Albpetrol), the state owned oil company, under Albpetrol'sexisting license with the Albanian National Agency for Natural Resources(AKBN). The Patos-Marinza and Ku§ova agreements became effective in March 2006and September 2007, respectively, and have a 25 year term with extensionoptions at the Company's election for further five year increments, subject togovernment and regulatory approvals.
2. BASIS OF PREPARATION
(a) Statement of compliance
These consolidated financial statements have been prepared in accordance withInternational Financial Reporting Standards (IFRS) and are the Company's firstIFRS consolidated annual financial statements. IFRS 1 "First-time Adoption ofIFRS" 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 costbasis except for derivative financial instruments and held-for-tradingfinancial assets measured at fair value with changes in fair value recorded inprofit or loss. The methods used to measure fair values are discussed in note4.
(c) Functional and presentation currency
Items included in the financial statements of each of the Group's entities aremeasured using the currency of the primary economic environment in which theentity operates (functional currency). The functional currency of the parententity is Canadian dollars. These consolidated financial statements arepresented in United States (US) dollars (presentation currency), which is thefunctional 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 withIFRS requires management to make estimates and use judgment regarding thereported amounts of assets and liabilities and disclosures of contingent assetsand liabilities as at the date of the consolidated financial statements and thereported amounts of revenues and expenses during the year. By their nature,estimates are subject to measurement uncertainty and changes in such estimatesin future periods could require a material change in the financial statements.Accordingly, actual results may differ from the estimated amounts as futureconfirming events occur. Significant estimates and judgments made by managementin the preparation of these consolidated financial statements are as follows:
Recoverability of asset carrying values
The recoverability of development and production asset carrying values areassessed at a cash generating unit (CGU) level. Determination of whatconstitutes a CGU is subject to management judgments. The asset composition ofa CGU can directly impact the recoverability of the assets included therein.The key estimates used in the determination of cash flows from oil reservesinclude 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 depreciationAmounts recorded for depletion and depreciation and amounts used for impairmentcalculations are based on estimates of total proved and probable petroleum andnatural gas reserves and future development capital. By their nature, theestimates of reserves, including the estimates of future prices, costs andfuture cash flows, are subject to measurement uncertainty. Accordingly, theimpact to the consolidated financial statements in future periods could bematerial.
Decommissioning obligation
Amounts recorded for decommissioning obligation and the related accretionexpense require the use of estimates with respect to the amount and timing ofdecommissioning expenditures. Actual costs and cash outflows can differ fromestimates because of changes in laws and regulations, public expectations,market conditions, discovery and analysis of site conditions and changes intechnology. Other provisions are recognized in the period when it becomesprobable 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 theestimation of what the ultimate payout will be using pricing models such as theBlack-Scholes option pricing model which is based on significant assumptionssuch as volatility, dividend yield and expected term of options and warrants.Several compensation plans are also performance based and are subject tomanagement's judgment as to whether or not performance criteria will be met.
Deferred taxes
Tax interpretations, regulations and legislation in the various jurisdictionsin which the Company operates are subject to change. As such income taxes aresubject to measurement uncertainty. Deferred income tax assets are assessed bymanagement at the end of the reporting period to determine the likelihood thatthey will be realized from future taxable earnings.
3. SIGNIFICANT ACCOUNTING POLICIES
The accounting policies set out below have been applied consistently to all periods presented in these consolidated financial statements, and have been applied consistently by the Group.
(a) Basis of consolidation(i) Subsidiaries Subsidiaries are entities controlled by the Company. Control exists when the Company has the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities. In assessing control, potential voting rights that currently are exercisable are taken into account. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases. (ii) Transactions eliminated on consolidation Intercompany balances and transactions, and any unrealized income and expenses arising from intercompany transactions, are
eliminated
in preparing the consolidated financial statements.
(b) Foreign currency transactions
The functional currency for each entity is the currency of the primary economic environment in which it operates. The functional currency of the Albanian segment is the US dollar. Foreign currency denominated transactions and balances for this segment are translated to US dollars as follows:
(i) Monetary assets and liabilities are translated at the rates prevailing at each reporting date; (ii) Non-monetary assets and liabilities are translated to the functional currency at the historical exchange rate; (iii) Income and expenses for the period are translated at the average exchange rate for the period; and (iv) Gains and losses arising from foreign currency translation are recognized in net income. The results and financial position of the Canadian segment has a Canadiandollar functional currency, which is different from the presentation currency.The Company translates foreign currency denominated transactions and balancesrelated 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 Ku§ova 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) InventoryInventory is comprised of crude oil, diluent, diesel and other stocks, and isvalued at the lower of average cost of production and net realizable value(estimated selling price in the ordinary course of business, less the costs ofcompletion 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 paymentsThe grant date fair value of warrants awarded to employees, directors andservice providers is measured using the Black-Scholes option pricing model.The grant date fair value of options awarded to employees, directors andservice providers is measured using the Black-Scholes option pricing model andrecognized in the statement of comprehensive income, with a correspondingincrease in contributed surplus over the vesting period. A forfeiture rate isestimated on the grant date and is adjusted to reflect the actual number ofoptions that vest. Upon exercise of the option, consideration received,together with the amount previously recognized in contributed surplus, isrecorded as an increase to share capital.
(h) Decommissioning obligation
A provision is recognized if, as a result of a past event, the Company has apresent legal or constructive obligation that can be estimated reliably, and itis probable that an outflow of economic benefits will be required to settle theobligation. Provisions are determined by discounting the expected future cashflows at a pre-tax risk-free rate that reflects current market assessments ofthe time value of money and the risks specific to the liability. Provisions arenot 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'sbest estimate of expenditures required to settle the present obligation at thebalance sheet date. Subsequent to the initial measurement, the obligation isadjusted at the end of each period to reflect the passage of time and changesin the estimated future cash flows underlying the obligation. The increase inthe provision due to the passage of time is recognized as accretion withinfinance expenses whereas increases/decreases due to changes in the estimatedfuture cash flows are capitalized. Such capitalized costs for resourceproperties are amortized as part of depletion and depreciation using theunit-of-production method. Actual costs incurred upon settlement of thedecommissioning obligation are charged against the provision to the extent theprovision was established.
(i) Revenue
Revenue from the sale of the Company's oil is recorded when the significantrisks and rewards of ownership of the product is transferred to the buyer whichis usually when legal title passes to the external party. This is generally atthe 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 carryingamounts of assets and liabilities for financial reporting purposes and theamounts used for taxation purposes. Deferred tax is not recognized on theinitial recognition of assets or liabilities in a transaction that is not abusiness combination. In addition, deferred tax is not recognized for taxabletemporary differences arising on the initial recognition of goodwill. Deferredtax is measured at the tax rates that are expected to be applied to temporarydifferences when they reverse, based on the laws that have been enacted orsubstantively enacted by the reporting date. Deferred tax assets andliabilities are offset if there is a legally enforceable right to offset, andthey relate to income taxes levied by the same tax authority on the sametaxable entity, or on different tax entities, but they intend to settle currenttax liabilities and assets on a net basis or their tax assets and liabilitieswill be realized simultaneously.A deferred tax asset is recognized to the extent that it is probable thatfuture taxable profits will be available against which the temporary differencecan be utilized. Deferred tax assets are reviewed at each reporting date andare reduced to the extent that it is no longer probable that the related taxbenefit 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 ofthese items related to consolidation, while the remaining one addresses fairvalue measurement. All of the new standards are effective for annual periodsbeginning on or after January 1, 2013. Early adoption is permitted.IFRS 10 "Consolidated Financial Statements" introduces a new principle-baseddefinition of control, applicable to all investees to determine the scope ofconsolidation. The standard provides the framework for consolidated financialstatements 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 ownaccounting model. A "joint operation" continues to be accounted for usingproportionate consolidation, where a "joint venture" must be accounted forusing equity accounting. This differs from IAS 31, where there was the choiceto use proportionate consolidation or equity accounting for joint ventures. A"joint operation" is defined as the joint operators having rights to theassets, and obligations for the liabilities, relating to the arrangement. In a"joint venture", the joint ventures partners have rights to the net assets ofthe arrangement, typically through their investment in a separate joint ventureentity.IFRS 12 "Disclosure of Interests in Other Entities" is a new standard, whichcombines all of the disclosure requirements for subsidiaries, associates andjoint 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", whichcovers the classification and measurement of financial assets as part of itsproject to replace IAS 39 "Financial Instruments: Recognition and Measurement."In October 2010, the requirements for classifying and measuring financialliabilities were added to IFRS 9. Under this guidance, entities have the optionto recognize financial liabilities at fair value through earnings. If thisoption is elected, entities would be required to reverse the portion of thefair value change due to a company's own credit risk out of earnings andrecognize the change in other comprehensive income. IFRS 9 is effective for theCompany on January 1, 2015. Early adoption is permitted and the standard isrequired 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 thedetermination of fair value, for both financial and non-financial assets andliabilities. Fair values have been determined for measurement and/or disclosurepurposes based on the following methods. When applicable, further informationabout the assumptions made in determining fair values is disclosed in the notesspecific 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 recognizedin a business combination, is based on market values. The market value of PP&Eand E&E assets is the estimated amount for which the assets could be exchangedon the acquisition date between a willing buyer and a willing seller in anarm's length transaction after proper marketing wherein the parties had eachacted knowledgeably, prudently and without compulsion. The market value of oiland natural gas interests (included in PP&E) and intangible exploration assetsis estimated with reference to the discounted cash flows expected to be derivedfrom oil and natural gas production based on externally prepared reservereports. The risk-adjusted discount rate is specific to the asset withreference 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-terminvestments, accounts receivable and accounts payable and accrued liabilitiesis estimated as the present value of future cash flows, discounted at themarket 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 theirshort term to maturity, or in the case of long-term debt, the fair valueapproximates its carrying value as it bears interest at floating rates.
(c) Derivatives
The fair value of financial commodity contracts is determined by discountingthe difference between the contracted prices and published forward price curvesas at the balance sheet date, using the remaining contracted oil and naturalgas volumes and a risk-free interest rate (based on published governmentrates).
(d) Stock options and warrants
The fair value of employee stock options and warrants is measured using aBlack-Scholes option pricing model. Measurement inputs include share price onmeasurement date, exercise price of the instrument, expected volatility (basedon weighted average historic volatility adjusted for changes expected due topublicly available information), weighted average expected life of theinstruments (based on historical experience and general option and warrantholder behavior), expected dividends, expected forfeiture rate and therisk-free interest rate (based on government bonds).
(e) Financial assets and liabilities
The following tables provide fair value measurement information for financialassets and liabilities as of December 31, 2011 and 2010. The carrying value ofcash and cash equivalents, restricted cash, short-term investments, accountsreceivable, accounts payable and accrued liabilities and long-term debtincluded in the consolidated statement of financial position approximate fairvalue due to the short term nature of those instruments or the indexed rate ofinterest on the long-term debt. These assets and liabilities are not includedin the following tables: Fair value measurements using Quoted prices in Significant active other Significant markets observable unobservable Carrying Fair (level inputs inputsDecember 31, 2011 ($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 Significant prices in other Significant active
observable unobservable
Carrying Fair markets inputs inputsDecember 31, 2010 ($000s) amount value (level 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 theabove risks, the Company's objectives, policies and processes for measuring andmanaging risk, and the Company's management of capital. Further quantitativedisclosures are included throughout these consolidated financial statements.The Board of Directors oversees managements' establishment and execution of theCompany's risk management framework. Management has implemented and monitorscompliance with risk management policies. The Company's risk managementpolicies are established to identify and analyze the risks faced by theCompany, to set appropriate risk limits and controls, and to monitor risks andadherence 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 $0.2million (2010 - $0.2 million) of other trade receivables, as summarized below:2011 ($000s) Current 30-60 days 61- 90 days Over 90 days Total Albania $ 28,697 $ 1,287 $ 5,076 $ 20,767 $ 55,827 Canada 179 - - - 179 $ 28,876 $ 1,287 $ 5,076 $ 20,767 $ 56,006 2010 ($000s) Current 30-60 days 61- 90 days Over 90 days Total Albania $ 25,590 $ 3,019 $ 408 $ - $ 29,017 Canada 216 - - - 216 $ 25,806 $ 3,019 $ 408 $ - $ 29,233
In Albania, the Company considers any amounts greater than 60 days as pastdue. The accounts receivable, included in the table, past due or not past dueare not impaired. They are from counterparties with whom the Company has ahistory of collection and the Company considers the accounts receivablecollectible. Domestic receivables are due by the end of the month followingproduction and export receivables are collected within 30 days from the date ofshipment. The Company's policy to mitigate credit risk associated with thesebalances 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 domesticcustomer of which $25.8 million (2010 - $0.4 million) is past due. Thecustomer has confirmed the outstanding amount and the Company has finalized arepayment plan.
In Canada, no amounts are considered past due or impaired.
The Company manages the credit exposure related to cash and cash equivalentsand short-term investments by selecting counter parties based on credit ratingsand monitors all investments to ensure a stable return, avoiding complexinvestment 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 meetexpected operational expenses for a minimum period of 30 days, including theservicing of financial obligations; this excludes the potential impact ofextreme circumstances that cannot reasonably be predicted, such as naturaldisasters. To achieve this objective, the Company prepares annual capitalexpenditure budgets, which are regularly monitored and modified as considerednecessary. Further, the Company utilizes authorizations for expenditures onboth operated and non-operated projects to further manage capitalexpenditures. To facilitate the capital expenditure program, the Company hascredit facilities with three international banks, as disclosed in note 16. TheCompany also attempts to match its payment cycle with collection of petroleumrevenues. The Company maintains a close working relationship with the banksthat provide its credit facilities.The contractual maturities of financial liabilities, at December 31, 2011, areas follows: Carrying 2015 ($000s) Amount 2012 2013 2014 and after Accounts payable and accrued liabilities $ 52,109 $ 52,109 $ - $ - $ - Operating loan 12,298 12,298 - - - Term loans 8,074 889 2,089 1,496 3,600 Revolving loans 50,000 - 33,500 8,250 8,250 $ 122,481 $ 65,296 $ 35,589 $ 9,746 $ 11,850 (d) Market riskMarket risk is the risk that changes in market prices, such as foreign exchangerates, interest rates and commodity prices, will affect the Company's income orthe value of the financial instruments. The objective of market risk managementis 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 theCanadian dollar (CAD) against the US dollar (USD), with all other variablesheld 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 2010because 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 - 1USD: CAD$1.03) and the exchange rate at December 31, 2011 was 1 USD equalsCAD$1.02 (2010 - 1 USD: CAD$0.99).As at December 31, 2011, a 10% change in the foreign exchange rate of theAlbanian Lek against the USD, with all other variables held constant, wouldaffect after tax net income for the year by $3.9 million (2010 - $1.8million). The sensitivity is higher in 2011 as compared to 2010 due to theincrease in Albania Lek accounts payable and accrued liabilities. The averageexchange rate during the year was 1 USD equals 0.01 Lek (2010 - 1 USD: 0.01Lek) 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 70,115cash equivalents Accounts 181 - 178 215 - 216receivable 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 riskInterest rate risk is the risk that future cash flows will fluctuate as aresult of changes in market interest rates. The Company is exposed to interestrate fluctuations on its operating, term and revolving loans which bear afloating rate of interest. As at December 31, 2011, a 10% change in theinterest rate, with all other variables held constant, would affect after taxnet income for the year by $0.3 million (2010 - $0.2 million), based on theaverage debt balance outstanding during the year. The sensitivity in 2011 ishigher as compared to 2010 mainly due to the increase in revolving loansoutstanding.
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 willfluctuate as a result of changes in commodity prices. Commodity prices for oilare impacted by not only the relationship between the Canadian and US dollarbut 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 useof various financial derivative forward sale contracts. The Company does notapply hedge accounting for these contracts. The Company's production isusually sold using "spot" or near term contracts, with prices fixed at the timeof 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 aquality 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 heldconstant, 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 forthe amounts the Company would receive or pay to terminate the oil contracts atyear-end. The Company paid a $6.6 million premium to enter into thesefinancial oil contracts on February 28, 2011. At December 31, 2011, theestimated 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 endedDecember 31, 2011 (2010 - nil).
(e) Capital management
The Company's policy is to maintain a strong capital base so as to maintaininvestor, creditor and market confidence and to sustain future development ofthe business. The Company manages its capital structure and makes adjustmentsto it in the light of changes in economic conditions and the riskcharacteristics of the underlying oil assets. The Company considers its capitalstructure to include shareholders' equity, long-term debt and working capital.In order to maintain or adjust the capital structure, the Company may issueshares and adjust its capital spending to manage current and projected debtlevels.The Company monitors capital based on the ratio of debt to funds fromoperations. This ratio is calculated as net debt (outstanding long-term debtless working capital before current portion of long-term debt) divided by fundsfrom operations (cash provided by operating activities before changes innon-cash working capital). The Company's strategy is to maintain a ratio of nomore than 1.5 to 1. This ratio may increase at certain times as a result ofacquisitions. In order to monitor this ratio, the Company prepares annualcapital expenditure budgets, which are updated as necessary depending onvarying factors including current and forecast prices, successful capitaldeployment and general industry conditions. The annual and updated budgets areapproved by the Board of Directors.As at December 31, 2011, the ratio of debt to funds from operations was asurplus of 0.16 (2010 - surplus of 1.54). The lower surplus was due to thereduction in net debt from a surplus of $109.1 million to a surplus of $23.1million and an increase in funds from operations from $70.9 million to $147.9million.
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 weremet as at December 31, 2011 and 2010. The Company has not paid or declared anydividends since the date of incorporation, nor are any contemplated in theforeseeable future.
6. KEY MANAGEMENT PERSONNEL COMPENSATION
Key management personnel compensation includes all compensation paid toexecutive management and members of the Board of Directors and is comprised ofthe 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 optionsgranted to key management personnel as recorded in the financial statements.7. FINANCE INCOME AND EXPENSE($000s) 2011 2010 Finance income Interest income $ 640 $ 732 Net foreign exchange gain - 71 $ 640 $ 803 Finance expense Interest and bank charges $ 2,656 $ 2,581 Net foreign exchange loss 458 - Amortization of deferred financing costs (note 11) 734 2,789 Accretion of long-term debt (note 11) 2,555 - Accretion of decommissioning obligation (note 19) 460 302 $ 6,863 $ 5,672 Net finance expense $ 6,223 $ 4,869 8. SUPPLEMENTAL INFORMATION
a) Changes in non-cash working capital
($000s) 2011 2010 Operating activities Change in current assets Accounts receivable $ (26,773) $ (5,875) Inventory (10,213) (2,168) Deposits and prepaid expenses (839) (10,725) Change in current liabilities
Accounts payable and accrued liabilities 22,082 (2,946)
$ (15,743) $ (21,714) Investing activities Change in current liabilities
Accounts payable and accrued liabilities $ 6,786 $ 6,682
b) Income statement presentation
The Company's consolidated statement of comprehensive income is prepared primarily by nature of expense, with the exception of employee compensation costs, which are included in both operating and general and administrative expenses.
The following table details the amount of total employee compensation costs included in operating and general and administrative expenses in the consolidated statements of comprehensive income.
($000s) 2011 2010 Operating expenses $ 4,624 $ 3,442
General and administrative expenses 5,575 3,406
Total employee compensation costs $ 10,199 $ 6,849
9. INCOME TAX EXPENSE
Deferred income tax expense relates to the Albanian operations and results fromthe 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 byapplying the cumulative Canadian federal and provincial income tax rates to theincome 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 itsforeign subsidiaries and branches. As at December 31, 2011, the Company has nodeferred tax liabilities in respect of these temporary differences.
10. PROPERTY, PLANT AND EQUIPMENT (PP&E)
Equipment, Petroleum Furniture ($000s) Interests and Fixtures Total Cost or deemed cost Balance at January 1, 2010 $ 185,778 $ 3,882 $ 189,660 Exchange differences 192 44 236 Additions 126,063 1,761 127,824 Balance at December 31, 2010 312,033 5,687 317,720 Exchange differences (84) (52) (136) Additions 258,582 4,095 262,677 Balance at December 31, 2011 $ 570,531 $ 9,730 $ 580,261 Accumulated depletion and depreciation Balance at January 1, 2010 $ - $ 1,736 $ 1,736 Exchange differences - 30 30 Depletion and depreciation - 566 22,511 Balance at December 31, 2010 21,945 2,332 24,277 Exchange differences - (21) (21) Depletion and depreciation 39,420 947 40,367 Balance at December 31, 2011 $ 61,365 $ 3,258 $ 64,623 Equipment, Petroleum Furniture ($000s) Interests and Fixtures Total Net book value
At January 1, 2010 $ 185,778 $ 2,146 $ 187,924
At December 31, 2010 $ 290,088 $ 3,355 $ 293,443
At December 31, 2011 $ 509,166 $ 6,472 $ 515,638
The depletion expense calculation for the year ended December 31, 2011 included $1.9 billion (2010 - $1.2 billion) for estimated future development costs associated with proved and probable reserves in Albania.
The Company capitalized general and administrative expenses and share-basedpayments of $14.8 million during the year ended December 31, 2011 (2010 - $7.8million) that were directly related to exploration and development activitiesin 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 Ku§ova 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 takeoverof production and royalty payments thereon for all remaining Albpetrol activewell production and also expansion of the project area and development plan toinclude all of the contract area of the Patos-Marinza oilfield concession. Theagreement was signed on March 31, 2011, however is subject to government andregulatory approvals. Upon receipt of the required approvals, the Company willpay $34 million to Albpetrol under the terms of the agreement. The Companywill become the sole operator and Albpetrol will cease to conduct all petroleumoperations 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 syndicateof underwriters and issued an aggregate of 12,903,228 common shares at a priceof CAD$7.75 per common share on a bought deal basis, resulting in grossproceeds of $96.2 million. Commissions and share issue costs were $4.3million.14. EARNINGS PER SHARE
The following table summarizes the calculation of basic and diluted weighted average number of common shares:
2011 2010
Weighted-average number of common shares outstanding - basic 247,148,449
236,726,203
Dilutive effect of stock options 5,176,657
6,975,414 Dilutive effect of warrants 3,002,497 3,294,975
Weighted-average number of common shares outstanding - diluted 255,327,603
246,996,592
The average market price of the Company's shares for purposes of calculatingthe dilutive effect of share options was based on quoted market prices for theyear that the options were outstanding. Excluded from diluted earnings pershare is the effect of 6,904,999 options for the year ended December 31, 2011(480,000 options for 2010), as their effect is anti-dilutive.
15. WARRANTS
A summary of the changes in warrants is presented below:
Number of Weighted Average Warrants Exercise Price (CAD$)
Outstanding, January 1, 2010 6,140,333 $ 2.42 Transferred to share capital on exercise (1,277,267) 2.63 Outstanding, December 31, 2010 4,863,066 2.37 Transferred to share capital on exercise (174,333) 2.37 Outstanding, December 31, 2011 4,688,733 $ 2.37 The following table summarizes the outstanding and exercisable warrants atDecember 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 DEBTAs at December 31, 2011 the Company had credit facilities with threeinternational banks, including Raiffeisen Bank, the European Bank forReconstruction and Development (EBRD) and the International Finance Corporation(IFC), as summarized below: Facility Outstanding ($000s) Amount Amount 2011 2010 Raiffeisen Bank Operating loan (a) $ 20,000 $ 12,298 $ 19,741 Term loan - 2006 (b) - - 3,125 Term loan - 2009 (c) 2,074 2,074 2,963 EBRD and IFC*
Environmental term loan (d) 10,000 6,000
-
Revolving loan - Tranche 1 (e) 50,000 50,000
-
Revolving loan - Tranche 2 (e) 50,000 -
- 132,074 70,372 25,829 EBRD and IFC*
Transfer from deferred financing costs - (10,493)
- (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 raterelative 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 classifiedas current. Subsequent to December 31, 2011, the operating loan has beenapproved 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 isrepayable in equal monthly installments of $74,100 ending on April 30, 2014. Asat December 31, 2011, the entire facility was utilized. Of the amountoutstanding, $0.9 million is classified as current and $1.2 million aslong-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 forenvironmental and social programs pertinent to the Company's activities inAlbania. 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. AtDecember 31, 2011, $6.0 million of the facility was drawn. Principal repaymentscommence in April 2013 in bi-annual installments of $0.5 million, or pro-ratato 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 $50.0million tranches, of which Tranche I is fully-utilized by the Company. TrancheII becomes available subject to mutual agreement among the Company, IFC andEBRD, when production exceeds 10,000 barrels of oil per day and the Brent oilprice exceeds $62 per barrel for twenty consecutive trading days. The interestrate is based on LIBOR plus a margin of 4.5% and is reduced to LIBOR plus amargin of 4.0% if the Brent oil price exceeds $90 per barrel for sixtyconsecutive trading dates. A standby fee of 2.0% is charged on any unutilizedTranche I portion and Tranche II portion, when it becomes available. AtDecember 31, 2011, Tranche I has been drawn down by $50.0 million of which theentire amount is classified as long-term. For each of Tranche I and TrancheII, the amounts decline to $16.5 million on October 15, 2013, $8.3 million onOctober 14, 2014 with final repayment due on October 15, 2015. Principalrepayments 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 PAYMENTSThe Company has established a "rolling" stock option plan. The number of sharesreserved for issuance may not exceed 10% of the total number of issued andoutstanding shares and, to any one optionee, may not exceed 5% of the issuedand outstanding shares on a yearly basis or 2% if the optionee is engaged ininvestor relations activities or is a consultant. The exercise price of eachoption shall not be less than the market price of the Company's stock at thedate of grant. Under the terms of the stock option plan, the exercise of stockoptions will be settled by the issuance of shares of the Company.Options issued vest one-third immediately (after three to six months followingthe date of the grant for new employees), one-third after one year followingthe 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:
Weighted Average Number of Options 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 Weighted Average Remaining Range of Exercise Price Number of Exercise Price Contractual Life
(CAD$) Options (CAD$) (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 calculatedshare-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 - $7.9million) was charged to earnings and $13.5 million (2010 - $6.6 million) wascapitalized.The weighted average fair market value per option granted during the yearsended December 31, 2011 and 2010 and the weighted average assumptions used inthe Black-Scholes option pricing model in their determination were as follows: 2011 2010 Fair value per option (CAD$) 3.19 3.96 Risk-free interest rate (%) 2.29 2.66 Forfeiture rate (%) 5 5 Volatility (%) 46 70 Expected life (years) 5 5 18. SEGMENTED INFORMATION
The Company defines its reportable segments based on geographic locations.
Year ended December 31, 2011 ($000s) Albania Canada
Total Revenues $ 339,918 $ - $ 339,918 Royalties (63,941) - (63,941) 275,977 - 275,977 Unrealized loss on financial commodity contracts - (2,904) (2,904) 275,977 (2,904) 273,073 Operating expenses 60,864 - 60,864
Sales and transportation expenses 45,460 -
45,460
General and administrative expenses 7,792 5,981
13,773 Depletion and depreciation 40,116 251 40,367 Share-based payments 4,529 6,512 11,041 158,761 12,744 171,505 117,216 (15,648) 101,568 Net finance expense 1,943 4,280 6,223
Income (loss) before income tax 115,273 (19,928)
95,345 Deferred income tax expense (59,349) - (59,349)
Net income (loss) for the year 55,924 (19,928)
35,996 Other comprehensive income Currency translation adjustment - 315 315
Comprehensive income (loss) for the year $ 55,924 $ (19,613) $
36,311 Assets, December 31, 2011 $ 614,830 $ 46,386 $ 661,216
Liabilities, December 31, 2011 $ 200,360 $ 47,944 $
248,304 Additions to PP&E $ 241,902 $ 852 $ 242,754 Year ended December 31, 2010 ($000s) Albania Canada Total Revenues $ 170,376 $ - $ 170,376 Royalties (33,682) - (33,682) 136,694 - 136,694 Operating expenses 36,744 - 36,744 Sales and transportation expenses 18,847 -
18,847
General and administrative expenses 6,020 4,530 10,550 Depletion and depreciation 22,352 159 22,511 Share-based payments 2,247 5,653 7,900 86,210 10,342 96,552 50,484 (10,342) 40,142 Net finance expense 1,536 3,333 4,869 Income (loss) before income tax 48,948 (13,675) 35,273 Deferred income tax expense (24,748) - (24,748) Net income (loss) for the year 24,200 (13,675) 10,525 Other comprehensive income Currency translation adjustment - 6,094 6,094 Comprehensive income (loss) for the $ 24,200 $ (7,581) $ 16,619 year Assets, December 31, 2010 $ 356,132 $ 109,466 $ 465,598 Liabilities, December 31, 2010 $ 117,548 $ 1,783 $ 119,331 Additions to PP&E $ 119,557 $ 160 $ 119,717
Revenues by geographical region are as follows:
($000s) 2011 2010 Albania- domestic $ 68,235 $ 23,942 Albania- export 271,683 146,434 $ 339,918 $ 170,376
For the year ended December 31, 2011, revenues of $336.0 million (2010 - $167.3 million), were derived from six customers (2010 - five customers) who individually amounted to over 10% or more of the Company's revenues.
19. DECOMMISSIONING OBLIGATION
($000s) 2011 2010
Balance, beginning of year $ 6,622 $ 4,796
Incurred 3,854 1,994 Revisions 2,625 (470) Accretion 460 302 Balance, end of year $ 13,561 $ 6,622 The Company's decommissioning obligation results from its ownership interest inoil assets including well sites and gathering systems. The totaldecommissioning obligation is estimated based on the Company's net ownershipinterest in all wells and facilities, estimated costs to reclaim and abandonthese wells and facilities and the estimated timing of the costs to be incurredin future years. In Albania, the Company estimated the total undiscountedamount required to settle the decommissioning obligation at December 31, 2011is $58.5 million (2010 - $30.9 million). This obligation will be settled at theend of the Company's 25 year license of which 19 years are remaining. Theliability 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 certaincapital projects in Block "F". As at December 31, 2011, the Company hasincurred $1.5 million towards these projects. The Company has also secured nil(2010 - $1.5 million) for certain capital projects in the Ku§ova 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 underCanadian GAAP. These accounting policies have been applied for the year endedDecember 31, 2011, as well as to the opening statement of financial position onthe 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 GAAPto elect, at the time of adoption to IFRS, to measure oil and gas assets in thedevelopment and production phases by allocating the amount determined under theentity's previous GAAP for those assets to the underlying assets pro rata usingreserve volumes or reserve values as of that date. Bankers used reserve valuesas at January 1, 2010 to allocate the cost of development and production assetsto 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 usethe IFRS rules for business combinations on a prospective basis rather thanre-stating all business combinations. In respect of acquisitions prior toJanuary 1, 2010, any goodwill represents the amount recognized under CanadianGAAP.Bankers has elected the IFRS 1 exemption that allows the Company an exemptionon IFRS 2 "Share-Based Payments" to equity instruments which vested and settledbefore the Company's transition date to IFRS.Bankers has elected the IFRS 1 exemption that allows the Company an exemptionon IAS 21 "The Effects of Change in Foreign Exchange Rates". The cumulativetranslation differences for all foreign operations are deemed to be zero at thedate of transition to IFRS. Any retrospective translation differences arerecognized 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 transition to IFRS($000s) Note GAAP IFRS ASSETS Current assets Cash and cash $ 59,495 $ - $ 59,495 equivalents Short-term investments 7,275 - 7,275 Restricted cash 1,500 - 1,500 Accounts receivable 23,358 - 23,358 Inventory 2,031 - 2,031 Deposits and prepaid 5,899 - 5,899 expenses 99,558 - 99,558 Non-current assets Note receivable 2,749 - 2,749 Deferred financing costs f 14,383 1,441 15,824 Property, plant and 188,130 (206) 187,924 equipment a,f $ 304,820 $ 1,235 $ 306,055 LIABILITIES Current liabilities Accounts payable and $ 19,505 $ - 19,505 accrued liabilities $ Current portion of 4,639 - 4,639 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 liabilities 39,414 (522) 38,892 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 toIFRS as at the end of the last reporting year under Canadian GAAP - December31, 2010 Effect of transition Canadian to ($000s) Note GAAP IFRS IFRS ASSETS Current assets Cash and cash equivalents $ 106,619 $ - $ 106,619 Restricted cash 1,500 - 1,500 Accounts receivable 29,233 - 29,233 Inventory 4,199 - 4,199 Deposits and prepaid expenses 16,624 - 16,624 158,175 - 158,175 Non-current assets Deferred financing costs f 11,805 2,175 13,980 Property, plant and equipment b,d,e,f,g 297,434 (3,991) 293,443 $ 467,414 $ (1,816) $ 465,598 LIABILITIES Current liabilities Accounts payable and accrued liabilities $ 23,241 $
- $ 23,241
Current portion of long-term debt 4,014 - 4,014 27,255 - 27,255 Non-current liabilities Long-term debt 21,815 - 21,815 Decommissioning obligation b 5,496 1,126 6,622 Deferred tax liabilities g 69,541 (5,902) 63,639 124,107 (4,776) 119,331 SHAREHOLDERS' EQUITY Share capital 309,379 - 309,379 Warrants 1,597 - 1,597 Contributed surplus c 28,715 (580) 28,135 Accumulated other comprehensive income f - 6,094 6,094 Retained earnings (deficit) 3,616 (2,554) 1,062 343,307 2,960 346,267 $ 467,414 $ (1,816) $ 465,598 Reconciliation of the statement of comprehensive income for the year endedDecember 31, 2010 Effect of Canadian transition ($000s) Note GAAP to IFRS IFRS Revenues 170,376 - $ 170,376 $ $ Royalties (33,682) - (33,682) 136,694 - 136,694 Operating expenses 36,744 - 36,744 Sales and transportation 18,847 - 18,847 expenses General and administrative e 8,255 2,295 10,550 expenses Depletion and depreciation d,f 27,091 (4,580) 22,511 Share-based payments c 8,111 (211) 7,900 99,048 (2,496) 96,552 Finance income Interest income 732 - 732 Foreign exchange gain f 5,225 (5,154) 71 5,957 (5,154) 803 Finance expense Interest and bank charges 1,160 -
1,160
Amortization of deferred 2,789 - 2,789 financing costs Interest on long-term debt 1,421 - 1,421 Accretion b 425 (123) 302 5,795 (123) 5,672 Net finance income (expense) 162 (5,031) (4,869) Income before income tax 37,808 (2,535) 35,273 Deferred income tax expense g (23,543) (1,205) (24,748) Net income for the year 14,265 (3,740) 10,525
Other comprehensive income
Currency translation f - 6,094 6,094 adjustment Comprehensive income for the $ 14,265 $ 2,354 16,619 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 of10%. Under IFRS, the estimated cash flow to abandon and remediate the wellsand facilities has been risk adjusted therefore the provision is discounted ata risk-free rate in effect at the end of each reporting period. The change inthe decommissioning obligation each period as a result of changes in thediscount rate will result in an offsetting charge to PP&E. Upon transition toIFRS, the impact of this change was a $0.9 million increase in thedecommissioning obligation with a corresponding increase to the deficit on thestatement 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 comprehensiveincome for finance costs. The items under previous GAAP that were reclassifiedto finance expense were interest and bank charges, net foreign exchange loss,accretion of decommissioning obligation and amortization of deferred financingcosts.(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 oilproperties on a unit of production basis over proved plus probable reserves.The depletion policy under Canadian GAAP was based on units of production overproved reserves. In addition, depletion was calculated on the Albanianconsolidated cost centre under Canadian GAAP. IFRS requires depletion anddepreciation to be calculated based on individual components, separately.Accordingly, under IFRS, major workover expenditures have been depreciated on astraight-line basis over an estimated useful life of 5 years, whereas underCanadian GAAP, these expenditures were depleted with the oil properties on aunit-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 andshare-based payments are capitalized to the extent they are directlyattributable to PP&E and E&E. The Company has adjusted its capitalizationpolicy to comply with IFRS. For the year ended December 31, 2010, $2.3 millionof such costs are expensed under IFRS that were previously capitalized underprevious Canadian GAAP.
(f) Foreign currency translation
IFRS requires that the functional currency of each entity in a consolidatedgroup be determined separately based on the currency of the primary economicenvironment in which the entity operates. A list of primary and secondaryindicators is used under IFRS in this determination and these differ in contentand emphasis to a certain degree from those factors under Canadian GAAP. Theparent company operated with US dollar as functional currency under CanadianGAAP. The Company re-assessed the determination of the functional currency forthe parent company and determined the Canadian dollar as the functionalcurrency for this entity under IFRS. The impact of the change in functionalcurrency was an adjustment to deferred financing costs, property, plant andequipment and retained earnings. The adjustment to retained earnings at thedate of transition was $1.3 million (using the optional IFRS 1 exemptiondiscussed earlier). For the year ended December 31, 2010, the currencytranslation adjustment was other comprehensive income of $6.1 million.
(g) Deferred income taxes
The adjustment to deferred income taxes on transition relates to the openingadjustment to the decommissioning obligation and pre-exploration and evaluationcosts. The deferred income tax impact of the opening adjustment was areduction in deferred tax liability of $0.5 million with the correspondingchange recorded in deficit.Under IFRS, the acquisition of an asset other than in a business combinationdoes not give rise to any deferred income taxes based on the initialrecognition exemption. Under Canadian GAAP, any related deferred income taxeswere added to the cost of the asset. Accordingly, deferred income taxesrecorded on capitalized share-based payments under Canadian GAAP have beenadjusted 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
GAAPand IFRS presentation.For further information:
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: [email protected]: www.bankerspetroleum.comAIM NOMAD:Canaccord Genuity LimitedHenry Fitzgerald-O'Connor+44 20 7050 6500AIM JOINT BROKERS:Canaccord Genuity LimitedRyan Gaffney/ Henry Fitzgerald-O'Connor+44 20 7050 6500Macquarie Capital AdvisorsBen Colegrave/Paul Connolly+44 20 3037 5639(BNK)
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