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Anderson Energy Announces Strong 2011 Third Quarter Results, a 76% Increase in Oil and NGL Production and Doubled Cardium Proved Plus Probable Reserves

Tuesday, November 15, 2011

Anderson Energy Announces Strong 2011 Third Quarter Results, a 76% Increase in Oil and NGL Production and Doubled Cardium Proved Plus Probable Reserves07:47 EST Tuesday, November 15, 2011CALGARY, ALBERTA--(Marketwire - Nov. 15, 2011) - Anderson Energy Ltd. ("Anderson" or the "Company") (TSX:AXL) is pleased to announce its operating and financial results for the three and nine months ended September 30, 2011.HIGHLIGHTS-- Funds from operations in the third quarter were $12.7 million, up 61% from the third quarter of 2010. Earnings were $7.5 million in the third quarter of 2011.-- Total production was 7,351 BOED in the third quarter of 2011 compared to 7,292 BOED in the third quarter of 2010.-- Oil and NGL production averaged 2,345 bpd in the third quarter, up 76% from the prior year. Oil represented 1,709 bpd of total production and was 201% higher than last year.-- GLJ Petroleum Consultants ("GLJ") have completed an interim reserves report of all of the Company's oil and natural gas properties effective October 1, 2011. Proved plus probable ("P&P") BOE reserves have increased 13% from December 31, 2010 to 35.8 MMBOE.-- P&P reserves replacement was 650% for oil and 571% for oil and NGL. On a BOE basis, Anderson replaced 297% of production with P&P reserves in the first nine months of 2011.-- In the last nine months, Anderson increased proved developed producing ("PDP"), total proved ("TP") and P&P oil reserves by 72%, 28% and 62% respectively through Cardium drilling.-- Cardium P&P reserves more than doubled to 9.9 MMBOE representing 28% of total P&P reserves volumes and 46% of total P&P reserves value on a pre- tax 10% net present value ("NPV 10") basis. The Company's net asset value is estimated to be $1.56 per share.-- Anderson achieved a 23% reduction in drilling and completion costs in the Garrington and Willesden Green operating areas in the third quarter, making the average cost to drill and complete a well $2.3 million. To date in the fourth quarter of 2011, Anderson's drilling and completion costs in the Garrington field have been $2.1 million per well.-- Anderson announced a new Cardium light oil discovery in Ferrier on October 26, 2011, confirming an extension to the Ferrier Cardium G Oil Pool. By year end, a total of four wells are expected to be drilled in Ferrier.-- Capitalizing on the oil drilling success in the third quarter, the 2011 capital program has been increased to $145 million allowing for acceleration of capital spending that was originally planned for the first quarter of 2012. Anderson now expects to drill 36% more net wells than previously planned in 2011 and the net benefit is expected to be more oil production and cash flow from operations in 2012.FINANCIAL AND OPERATING HIGHLIGHTS(thousands of dollars, unless Three months ended Nine months ended otherwise stated) September 30 September 30 % % 2011 2010(i) Change 2011 2010(i) ChangeOil and gas sales(ii) $ 28,513 $ 18,928 51% $ 85,665 $ 62,511 37%Revenue, net of royalties(ii) $ 24,970 $ 17,263 45% $ 76,029 $ 55,756 36%Funds from operations $ 12,655 $ 7,876 61% $ 37,467 $ 27,234 38%Funds from operations per share Basic and diluted $ 0.07 $ 0.05 40% $ 0.22 $ 0.16 38%Earnings (loss) before effect of impairment or reversals thereof $ 6,667 $ (3,057) 318% $ 8,918 $ (5,251) 270%Earnings (loss) per share before effect of impairment or reversals thereof Basic and diluted $ 0.04 $ (0.02) 300% $ 0.05 $ (0.03) 267%Earnings (loss) $ 7,472 $(39,029) 119% $ 9,723 $(88,242) 111%Earnings (loss) per share Basic and diluted $ 0.04 $ (0.23) 117% $ 0.06 $ (0.52) 112%Capital expenditures, including acquisitions net of dispositions $ 49,713 $ 39,378 26% $ 118,351 $ 85,269 39%Bank loans plus cash working capital deficiency $ 108,583 $ 102,198 6%Convertible debentures $ 84,334 $ - 100%Shareholders' equity $ 195,251 $ 215,389 (9%)Average shares outstanding (thousands): Basic 172,550 172,400 - 172,534 169,569 2% Diluted 172,550 172,400 - 173,040 169,569 2%Ending shares outstanding (thousands) 172,550 172,400 -Average daily sales: Natural gas (Mcfd) 30,038 35,778 (16%) 31,972 36,668 (13%) Oil (bpd) 1,709 568 201% 1,615 469 244% NGL (bpd) 636 761 (16%) 667 762 (12%) Barrels of oil equivalent (BOED) 7,351 7,292 1% 7,610 7,342 4%Average prices: Natural gas ($/Mcf) $ 3.85 $ 3.43 12% $ 3.74 $ 4.12 (9%) Oil ($/bbl) $ 89.05 $ 68.24 30% $ 91.59 $ 70.77 29% NGL ($/bbl) $ 66.07 $ 51.41 29% $ 68.76 $ 53.89 28% Barrels of oil equivalent ($/BOE)(ii) $ 42.16 $ 28.21 49% $ 41.23 $ 31.19 32%Realized gain (loss) on derivative contracts ($/BOE) $ 1.29 $ - 100% $ (0.17) $ - (100%)Royalties ($/BOE) $ 5.24 $ 2.48 111% $ 4.64 $ 3.37 38%Operating costs ($/BOE) $ 11.22 $ 9.45 19% $ 11.30 $ 9.96 13%Transportation costs ($/BOE) $ 0.89 $ 0.26 242% $ 0.63 $ 0.19 232%Operating netback ($/BOE) $ 26.10 $ 16.02 63% $ 24.49 $ 17.67 39%Wells drilled (gross) 21 14 50% 41 43 (5%)(i) 2010 results have been restated to conform to International FinancialReporting Standards.(ii) Includes royalty and other income classified with oil and gas sales,but excludes realized and unrealized gains or losses on derivativecontracts.OPERATIONSCardium Horizontal Oil Drilling. In the third quarter of 2011, Anderson drilled 21 gross (18.0 net capital, 16.4 net revenue) Cardium horizontal oil wells. From May 1, 2010 to September 30, 2011, the Company has drilled 62 gross (50.4 net capital, 45.6 net revenue) wells and placed 58 gross (42.6 net revenue) Cardium oil wells on production. The Company plans to drill 51 gross (44.3 net capital, 39.1 net revenue) Cardium horizontal oil wells in 2011, which is 36% higher than previous estimates on a net revenue basis.Cardium Horizontal Oil Capital Costs. Anderson has been diligently reducing its drilling and completion costs with the application of new technology and other cost savings measures. Third quarter 2011 drilling and completion costs in the Garrington and Willesden Green areas are approximately 23% lower than those encountered in the first half of the year even with longer horizontal well lengths and additional fracture stimulation ("frac") stages.Garrington/Willesden Green Capital Costs:Period Average Drilling and Average Average Completion Number of Drilling Costs Completion Costs Frac Stages ($MM) Costs ($MM) ($MM) per Well2010 1.6 1.4 3.0 13First half of 2011 1.8 1.2 3.0 17Third quarter 2011 1.4 0.9 2.3 19----------------------------------------------------------------------------To date in the fourth quarter of 2011, Anderson's drilling and completion costs in the Garrington field have been $2.1 million per well.In the third quarter of 2011, the Company experimented with alternative completion technology to the commonly used open hole casing packer multi-stage fracture stimulation technology. The Company sees considerable benefits in addition to lower costs from the application of this technology. Anderson plans to utilize this technology in the Willesden Green, Garrington and Ferrier fields for its future Cardium horizontal oil wells.Ferrier Horizontal Cardium Oil Discovery. On October 26, 2011, Anderson announced a new Cardium light oil discovery in Ferrier with an extension to the Ferrier Cardium G oil pool. To date, one operated horizontal oil well and one outside operated horizontal oil well have been drilled. The Company owns or controls 13.8 gross (6.8 net) sections of land in the Ferrier area, with most of the land being a contiguous land block in Twp 37, Ranges 7 and 8 W5M. Based on in-house mapping, the Company estimates it has 30 gross (15.9 net) locations remaining to be drilled in Ferrier. A production tank battery and solution gas compressor have been built to handle the initial production from its operated lands. Two additional appraisal wells are planned to be drilled during the fourth quarter.Garrington Cardium Oil Pool Update. Anderson has identified a northern extension to its core Garrington field. Recent performance of wells drilled in the northern portion of the Garrington area have been above the average Garrington type curve. The Garrington battery consolidation project was completed in early August, with all of the Company's single well batteries connected to the central 15-34 tank battery. This project is expected to reduce operating and capital costs in this area. The 100% owned facility was connected by Plains Midstream Canada to the Rangeland Pipeline system on October 24, 2011. This facility is expected to process third party volumes and could represent an attractive source of processing fee income for Anderson.Garrington represented 59% of the Company's oil production in the third quarter of 2011. The Company is completing is reservoir computer simulation study to design a waterflood in the Garrington field.Cardium Land and Drilling Inventory. Anderson's Cardium prospective land inventory is 124.5 gross (74.0 net) sections, an increase of 23% over December 31, 2010. Approximately 85% of the Company's Cardium lands are located in the oil prone fairway and the balance is in the gas prone fairway. Using geological mapping and offset production information, the Company has high-graded a location list to drill in the oil prone fairway. The list includes 204 gross (129.8 net) horizontal locations to be drilled in the next few years (including wells drilled to date). Each location is a development location that is technically feasible and not contingent upon the drilling of other wells.Other Horizontal Oil Opportunities. The Company has identified five non-Cardium zones on its lands in central Alberta, with potential for horizontal oil drilling with multi-stage fracture stimulation, which is similar technology as used in Cardium horizontal drilling. These zones are Second White Specs, Belly River, Viking, Glauconite and Mannville. Anderson has 50.8 gross (29.1 net) sections of land in the emerging Second White Specs horizontal oil play. The Company is currently evaluating the timeline and level of participation to drill these horizons in 2012.Edmonton Sands Farm-In. Anderson announced a 200 well Edmonton Sands farm-in commitment on January 29, 2009 and drilled 126 wells in the winter of 2009/2010. The Company was planning to drill the remaining 74 wells during the upcoming winter. The terms of the farm-in agreement have been modified to extend the commitment date to March 31, 2013. With weak natural gas prices, it has been decided to defer drilling the remaining 74 wells until after 2012.RESERVESGLJ, an independent reserves evaluator, has completed an interim reserves report of all of the Company's oil and natural gas properties effective October 1, 2011, prepared in accordance with procedures and standards contained in the Canadian Oil and Gas Evaluation ("COGE") Handbook. The reserves definitions used in preparing the interim report are those contained in the COGE Handbook and the Canadian Securities Administrators National Instrument 51-101. This is not a year end reserves report. The October 1, 2011 report is the first step in the process and will be updated by GLJ for year end reserves reporting. As of October 1, 2011, the Company has 12.4 MMBOE PDP (30% oil and NGL), 19.5 MMBOE TP (23% oil and NGL) and 35.8 MMBOE P&P (27% oil and NGL) reserves. The price forecast used in the evaluation is shown in Management's Discussion and Analysis for the three and nine months ended September 30, 2011.P&P reserves replacement was 650% for oil and 571% for oil and NGL. On a BOE basis, Anderson replaced 297% of production with P&P reserves in the first nine months of 2011. The Company's P&P BOE reserves increased 13% since December 31, 2010.P&P reserves from the Cardium drilling program are 9.9 MMBOE at October 1, 2011, more than double the 4.7 MMBOE at December 31, 2010. Cardium reserves represent 28% of total P&P reserves volumes and 46% of total P&P reserves value on a pre-tax NPV 10 basis.Since the inception of the Cardium play 18 months ago and including production, the Company has added 10.5 MMBOE of P&P reserves with its Cardium drilling program.SUMMARY OF OIL AND GAS RESERVES October 1, 2011 Pre-tax Oil NGL Gas Total NPV 10 (Mbbls) (Mbbls) (MMcf) (MBOE) ($M)Proved developed producing 2,242 1,460 52,069 12,379 207,113Proved developed producing and proved developed non-producing 2,375 1,512 59,213 13,755 219,933Total proved 2,840 1,703 89,842 19,517 227,772Proved plus probable 6,334 3,185 157,525 35,773 349,575----------------------------------------------------------------------------SUMMARY OF OIL AND GAS RESERVES December 31, 2010 Pre-tax Oil NGL Gas Total NPV 10 (Mbbls) (Mbbls) (MMcf) (MBOE) ($M)Proved developed producing 1,303 1,376 52,498 11,428 166,058Proved developed producing and proved developed non-producing 1,471 1,426 59,955 12,889 175,619Total proved 2,226 1,673 97,313 20,117 184,248Proved plus probable 3,908 2,676 150,621 31,687 271,469----------------------------------------------------------------------------Oil now represents 18% of the Company's PDP, 15% of TP and 18% of P&P reserves as compared to 11%, 11% and 12% respectively at December 31, 2010. Anderson increased PDP, TP and P&P oil reserves by 72%, 28% and 62%, respectively, in the previous nine months.NET ASSET VALUATION(1)As at September 30, 2011($ millions, unless otherwise stated)P&P reserves (pre-tax NPV 10) $ 350Undeveloped land (excluding Cardium horizontal prospective lands) 5Cardium horizontal prospective lands (2) 118Unrealized hedging gains and stock option proceeds 18Bank loans plus cash working capital deficiency (109)Series B convertible debentures (46) -------Net asset value estimate, September 30, 2011 (1) $ 336Net asset value estimate per fully diluted share, September 30, 2011 (3,4) $ 1.56------------------------------------------------------------------------------------------------------------------------------------------------------(1) The net asset valuation ("NAV") shows what the Company's reserves wouldbe produced at using GLJ's October 1, 2011 price forecast and costs. Thevalue is a snapshot in time and based on various assumptions includingcommodity prices that vary over time. It should not be assumed that NAVrepresents the fair market value of Anderson shares. GLJ's price forecast atOctober 1, 2011 for the period 2012 to 2017 is an average of $0.57 per Mcflower than at January 1, 2011, which negatively impacted NPV 10 by approximately $30 million.(2) Cardium undeveloped land valued at $2.5 million per net section notbooked in the interim GLJ reserves report assuming $2.4 million NPV 10 pernet location drilled over a three year time span (49.4 net unbookedlocations).(3)For the purposes of this calculation at September 30, 2011, it wasassumed that the Series B convertible debentures (convertible at $1.70 pershare) would remain as debt and the Series A convertible debentures would beconverted at $1.55 per share and the outstanding shares were adjustedaccordingly.(4) Based on 215.1 million outstanding shares on a fully diluted basis.The NAV per share calculation discussed above does not include any upside associated with the Company's extensive land holdings prospective for horizontal oil in the Second White Specs, Viking, Belly River, Mannville and Glauconite zones. It also does not include any incremental value associated with the Company's shallow gas drilling inventory in a more supportive natural gas price environment.PRODUCTIONDuring the third quarter of 2011, the Company averaged 7,351 BOED, with oil and NGL volumes representing 32% of total volumes. Oil and NGL production for the three months ended September 30, 2011 was 2,345 bpd, up substantially from 1,329 bpd in the third quarter of 2010. Of this, 1,709 bpd or 73% is crude oil production, compared to 568 bpd or 43% in the third quarter of 2010. The Company's production in the third quarter of 2011 was negatively impacted by plant outages and a slow start to the third quarter drilling program caused by wet ground conditions. The Company also sold non-core heavy oil properties in the third quarter of 2011. Anderson estimates that production in the fourth quarter of 2011 could reach 8,200 BOED with oil and NGL production representing approximately 43% of total production. The Company estimates that 2011 total production will be at the mid point of its previously stated guidance of 7,500 to 8,000 BOED.Anderson estimates that oil and NGL production will average approximately 45% of total production in 2012 and that the Company will likely achieve the significant milestone of a balanced production profile sometime during the next twelve months.FINANCIAL RESULTSCapital expenditures were $49.7 million (net of proceeds on dispositions of $6.2 million) in the third quarter of 2011 with $43.7 million spent on drilling and completions and $11.4 million spent on facilities. This compares to capital expenditures of $39.4 million in the third quarter of 2010.Anderson's funds from operations were $12.7 million in the third quarter of 2011 compared to $7.9 million in the third quarter of 2010. The Company's average crude oil and natural gas liquids sales prices in the third quarter of 2011 were $89.05 and $66.07 per barrel compared to $68.24 and $51.41 respectively per barrel in the third quarter of 2010. The Company has entered into fixed price oil swaps for 2011 and 2012. The Company's unrealized gain on its oil hedge was $11.2 million for the nine months ended September 30, 2011. The Company's average natural gas sales price was $3.85 per Mcf in the third quarter of 2011 compared to $3.43 per Mcf in third quarter of 2010 and included a $0.8 million gain relation to physical fixed price sales contracts. The Company recorded earnings of $7.5 million in the third quarter of 2011 primarily due to the oil hedging gains, a stronger contribution to total revenue by additional oil volumes and higher oil and NGL prices. The Company's operating netback was $26.10 per BOE in the third quarter of 2011 compared to $16.02 per BOE in the third quarter of 2010. The increase in the operating netback was primarily due to the increase in oil and NGL prices and oil volumes. Anderson's field net operating income for its Cardium horizontal properties in the first nine months of 2011 was $63.78 per BOE as compared to $14.01 per BOE for the remainder of its properties (exclusive of hedging). Average wellhead natural gas Operating Funds from price Revenue netback operations ($/Mcf) ($/BOE) ($/BOE) ($/BOE)2009 (i) 3.95 27.74 15.07 11.262010 (i) 3.96 31.31 17.44 13.22First quarter of 2011 3.58 36.80 21.96 15.63Second quarter of 2011 3.79 44.71 25.47 19.75Third quarter of 2011 3.85 42.16 26.10 18.71----------------------------------------------------------------------------First quarter of 2012 estimate($90 to $100 WTI Canadian(ii) plus oil hedge 3.75 to 53.00 to 36.00 to 27.00 to program) 4.00(ii) 56.00 39.00 30.00----------------------------------------------------------------------------(i) 2009 results have not been restated to conform to InternationalFinancial Reporting Standards. 2010 results have been restated to conform toInternational Financial Reporting Standards.(ii) EstimateAs Anderson increases its oil production, its revenue per BOE, operating netback per BOE and funds from operations per BOE should increase and contribute to profitability in 2012. Royalties were $5.24 per BOE in the third quarter of 2011 compared to $5.37 per BOE in the second quarter of 2011. Operating expenses in the third quarter of 2011 were $11.22 per BOE, which was 7% lower than the second quarter of 2011. The second quarter of 2011 was affected by costs associated with temporary production facilities and wet weather.2011 CAPITAL PROGRAMDuring the third quarter of 2011, the Company's Board of Directors approved an increase in the capital program to $145 million, net of dispositions, to focus on the development of new Cardium oil discoveries and required facility infrastructure for new discoveries in Ferrier, Willesden Green and Garrington North. In addition, the Company will be evaluating with the drill-bit a potentially new core area for Cardium oil development in the Northwest Pembina/Carrot Creek areas. A portion of the capital budget increase is an acceleration of planned 2012 capital spending into 2011. The benefit of the acceleration is expected to be increased oil production and funds from operations in 2012. In 2011, the Company estimates it could drill up to 51 gross (44.3 net capital, 39.1 net revenue) Cardium horizontal oil wells, which is 36% higher on a net revenue basis than previous estimates.COMMODITY CONTRACTSCrude Oil. As part of its price management strategy, Anderson has entered into fixed price swap contracts based on the NYMEX crude oil price in Canadian dollars. The average for volumes and prices for these contracts is summarized below: Weighted Weighted average WTI average volume CanadianPeriod (bpd) ($/bbl)October 1, 2011 to December 31, 2011 1,500 94.18January 1, 2012 to March 31, 2012 1,500 104.63April 1, 2012 to December 31, 2012 1,000 103.93----------------------------------------------------------------------------The Company entered into the hedging contracts to protect its capital program and support its bank borrowing base. As the Company continues to grow its oil production, it will evaluate the merits of additional commodity hedging as part of a price management strategy.The mark to market value of the hedging contracts at September 30, 2011 was $9.2 million.Natural Gas. The Company has physically contracted to sell 15,000 GJ per day of natural gas at an average Canadian dollar AECO price of $4.06 per GJ, from July 1, 2011 to October 31, 2011. This equates to approximately 13.9 MMcfd at an average plant gate price of approximately $4.15 per Mcf. The Company recorded a $0.8 million gain, included in oil and gas sales in relation to these physical contracts.STRATEGYWith oil prices at or near present levels, the Company expects to be able to finance the foreseeable drilling program out of cash flow and currently available credit facilities, without the need for external financing. Anderson estimates its oil and NGL production will grow from 18% of total production in 2010 to 34% in 2011 to potentially 45% in 2012. Independent analysts currently estimate that funds from operations could range from $48 million to $59 million in 2011 and $72 million to $95 million in 2012, which is significant growth when compared to $36.5 million in funds from operations in 2010. Management believes that a strategy of cash flow growth through light oil horizontal drilling is the best solution in this period of anemic natural gas prices. As part of this transition from natural gas to oil, Anderson completed two convertible debenture financings with five to six year terms and conversion prices of $1.55 and $1.70 per common share. This provides the Company with better financial flexibility to make the transformation to a balanced oil and gas producer. Debt leverage is higher than some of its peers in 2011; however, with improving revenue from oil production in 2011 and 2012, leverage is expected to return to more typical levels for junior oil producers by the end of 2012. The Company believes it has the depth of prospects to stay the oil course and still bring forward natural gas prospects for drilling when economic conditions dictate. In a stronger natural gas market, the Company has a significant shallow gas inventory of over 850 gross locations that can be drilled. This asset is strategic and valuable to the Company longer term.Anderson will closely monitor commodity prices and adjust its capital spending plans appropriately to stay within bank lines. The Company is planning to divest of various non-core oil and natural gas properties outside of its Central Alberta core area and use the proceeds from the disposition to reduce bank debt and/or expand its Cardium oil drilling program.Over the last year, the Company has been able to move up the learning curve in the Cardium play with drilling, completion and production initiatives. Anderson is very focused on increasing its land position in the Cardium and utilizing new technologies to lower costs and enhance well performance.OUTLOOKOil prices continue to be strong, but volatile, and are expected to remain so in the near term. Natural gas prices are weak and the timing of natural gas price recovery to economic levels is uncertain. Anderson will continue to dedicate its capital program to light oil horizontal oil drilling as these prospects represent the best economics.By the end of 2011, Anderson estimates it will have 54.5 net revenue Cardium horizontal wells on production, up 28% from the end of the third quarter 2011. The Company has increased its Cardium development drilling inventory by 52% since December 31, 2010 and is becoming an industry leader in lowering Cardium per well capital costs, including a 23% reduction in the third quarter of 2011. Anderson believes it is well positioned in the play and the results from the Cardium program will help to peel the natural gas label off the stock price and reward shareholders with more of an oil company valuation. As oil production grows in 2011 and 2012, the impact that this higher priced commodity will have on its cash flow and earnings could be significant.Anderson's strategy of diversification into light oil drilling is now showing the benefits. Edmonton benchmark light oil prices continue to remain strong despite recent volatility in WTI Canadian oil prices. Anderson estimates that oil and NGL production could average 45% of total production in 2012 and that sometime in 2012, the Company could have a balanced production portfolio of oil and natural gas.For more information, we encourage investors to review our website at www.andersonenergy.ca.Brian H. Dau, President & Chief Executive OfficerNovember 15, 2011Management's Discussion and AnalysisFOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2011 AND 2010The following discussion and analysis of financial results should be read in conjunction with the unaudited interim consolidated financial statements of Anderson Energy Ltd. ("Anderson" or the "Company") for the three and nine months ended September 30, 2011, the unaudited interim consolidated financial statements for the three months ended March 31, 2011 and the audited consolidated financial statements and management's discussion and analysis ("MD&A") of Anderson for the years ended December 31, 2010 and 2009 and is based on information available as of November 14, 2011.The following information is based on the unaudited interim consolidated financial statements of the Company at September 30, 2011, as prepared by management. The financial data included in this interim MD&A is in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB") and interpretations of the International Financial Reporting Interpretations Committee ("IFRIC") that are expected to be effective or available for early adoption by the Company as at December 31, 2011, the date of the Company's first annual reporting under IFRS. The effective date of the transition to IFRS was January 1, 2010. The transition to IFRS has been reflected by restating previously reported financial statements for 2010. Previously, the Company's financial statements were prepared under Canadian generally accepted accounting principles ("CGAAP"). The adoption of IFRS does not impact the underlying economics of the Company's operations or its cash flows. Note 17 to the interim consolidated financial statements for the three months ended March 31, 2011 and note 16 to the interim consolidated financial statements for the three and nine months ended September 30, 2011 contain detailed descriptions of the Company's adoption of IFRS, including reconciliations of the consolidated financial statements previously prepared under CGAAP to those under IFRS.Production and reserves numbers are stated before deducting Crown or lessor royalties.Included in the discussion and analysis are references to terms commonly used in the oil and gas industry such as funds from operations, finding, development and acquisition ("FD&A") costs, operating netback and barrels of oil equivalent ("BOE"). Funds from operations as used in this report represent cash from operating activities before changes in non-cash working capital and decommissioning expenditures. See "Review of Financial Results - Funds from Operations" for details of this calculation. Funds from operations represent both an indicator of the Company's performance and a funding source for on-going operations. FD&A costs measure the cost of reserves additions and are an indicator of the efficiency of capital expended in the period. Operating netback is calculated as oil and gas revenues less royalties, operating expenses and transportation expenses and is a measure of the profitability of operations before administrative and financing expenditures. Production volumes and reserves are commonly expressed on a BOE basis whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil and natural gas measurement units into one basis for improved analysis of results and comparisons with other industry participants. These terms are not defined by IFRS or CGAAP and therefore are referred to as non-GAAP measures.All references to dollar values are to Canadian dollars unless otherwise stated.The abbreviations used in this discussion and analysis are located on the last page of this document.REVIEW OF FINANCIAL RESULTSOverview. For the three months ended September 30, 2011, funds from operations were $12.7 million, up 61% from the third quarter of 2010, even though sales volumes on a BOE basis were similar to the prior year, due to the Company's refocus on Cardium light oil drilling. Sales volumes for the three months ended September 30, 2011 averaged 7,351 BOED, which was 5% lower than the second quarter of 2011, mostly due to a reduction in gas sales volumes as discussed below.Capital additions, net of proceeds from dispositions were $49.7 million for the three months ended September 30, 2011. During the third quarter of 2011, the Company drilled 21 gross (18.0 net capital, 16.4 net revenue) Cardium light oil wells with a 100% success rate. The Company also tied in 17 gross (13.4 net revenue) Cardium light oil wells in the third quarter of 2011.Bank loans plus cash working capital deficiency were $108.6 million at September 30, 2011. On June 8, 2011, the Company completed a convertible subordinated debenture financing for proceeds, net of commission and expenses, of $43.9 million. Proceeds were initially used to pay down bank debt. The availability created in the credit facilities, along with cash flows, will be used to help finance the Company's 2011 and 2012 capital programs.Revenue and Production. In 2010, the Company changed its focus to oil prospects in light of the continued depressed natural gas market. During the third quarter of 2011, oil and natural gas liquids revenue represented 63% of total revenue compared to 38% for the third quarter of 2010.The Company suspended its shallow gas drilling program after the first quarter of 2010 until natural gas prices improve. Accordingly, natural production declines were not replaced, resulting in the following decreases in gas sales. Gas sales volumes for the three months ended September 30, 2011 decreased to 30.0 MMcfd from 32.0 MMcfd in the second quarter of 2011 and 35.8 MMcfd in the same period in 2010. Gas sales for the nine months ended September 30, 2011 were 32.0 MMcfd compared to 36.7 MMcfd for the nine months ended September 30, 2010.Oil sales for the three months ended September 30, 2011 averaged 1,709 bpd compared to 1,759 bpd in the second quarter of 2011 and 568 bpd for the third quarter of 2010. The decrease in volumes from the second quarter of 2011 is primarily due to the sale of heavy oil properties in the third quarter of 2011.Natural gas liquids sales for the three months ended September 30, 2011 averaged 636 bpd compared to 667 bpd in the second quarter of 2011 and 761 bpd for the third quarter of 2010. Natural gas liquids volumes were affected by natural declines, consistent with declines in gas production.The following tables outline production revenue, volumes and average sales prices for the periods ended September 30, 2011 and 2010.OIL AND NATURAL GAS REVENUE Three months ended Nine months ended September 30 September 30(thousands of dollars) 2011 2010 2011 2010Natural gas $ 9,834 $ 11,304 $ 31,788 $ 39,984Gain on fixed price natural gas contracts 818 - 818 1,302Oil(1) 14,002 3,567 40,377 9,061NGL 3,863 3,598 12,517 11,213Royalty and other (4) 459 165 951 ------------------------ ------------------------Total $ 28,513 $ 18,928 $ 85,665 $ 62,511----------------------------------------------------------------------------(1) The three month numbers exclude the realized and unrealized gains onderivative contracts of $0.9 million and $6.4 million respectively duringthe three months ended September 30, 2011 (September 30, 2010 - $Nil). Thenine month numbers exclude the realized loss and unrealized gain onderivative contracts of $0.4 million and $11.2 million respectively duringthe nine months ended September 30, 2011 (September 30, 2010 - $Nil).PRODUCTION Three months ended Nine months ended September 30 September 30 2011 2010 2011 2010Natural gas (Mcfd) 30,038 35,778 31,972 36,668Oil (bpd) 1,709 568 1,615 469NGL (bpd) 636 761 667 762 ------------------------------------------------Total (BOED) 7,351 7,292 7,610 7,342----------------------------------------------------------------------------PRICES Three months ended Nine months ended September 30 September 30 2011 2010 2011 2010Natural gas ($/Mcf)(1) $ 3.85 $ 3.43 $ 3.74 $ 4.12Oil ($/bbl)(2) 89.05 68.24 91.59 70.77NGL ($/bbl) 66.07 51.41 68.76 53.89 ------------------------ ------------------------Total ($/BOE)(2,3) $ 42.16 $ 28.21 $ 41.23 $ 31.19----------------------------------------------------------------------------(1) Price includes gain on fixed price natural gas contracts from the firstquarter of 2010 and the third quarter of 2011.(2) The three month numbers exclude the realized and unrealized gains onderivative contracts of $0.9 million and $6.4 million respectively duringthe three months ended September 30, 2011 (September 30, 2010 - $Nil). Thenine month numbers exclude the realized loss and unrealized gain onderivative contracts of $0.4 million and $11.2 million respectively duringthe nine months ended September 30, 2011 (September 30, 2010 - $Nil).(3) Includes royalty and other income classified with oil and gas sales.Anderson's average natural gas sales price was $3.85 per Mcf for the three months ended September 30, 2011, 2% higher than the second quarter of 2011 price of $3.79 per Mcf and 12% higher than the third quarter of 2010 price of $3.43 per Mcf. Anderson's average gas sales price was $3.74 per Mcf for the nine months ended September 30, 2011, compared to $4.12 per Mcf in the comparable 2010 period. The natural gas price includes a gain of $0.8 million (September 30, 2010 - $1.3 million) on the Company's fixed price natural gas contracts. The gas price before the gain was $3.64 per Mcf in the first nine months of 2011 (September 2010 - $3.99 per Mcf). Gas prices remain depressed as a result of increased supply of natural gas in the United States.Historically, Anderson has sold most of its gas at Alberta spot market prices. The Company is currently selling all of its unhedged gas production at the average daily index price. The Company has classified transportation costs as an offset to gas sales revenue as title transfers prior to transport on the applicable sales pipelines and transportation is being held by and charged by the gas purchasers. The Company has arranged firm service transportation agreements covering approximately 23 MMcfd of natural gas sales for various terms expiring in one to nine years.Oil prices for the third quarter of 2011 have decreased 10% from the second quarter of 2011, but are 30% higher when compared to the same period in 2010. Oil prices continue to remain strong compared to 2010, but are also volatile in response to various geopolitical events.Commodity Contracts. At September 30, 2011 the following derivative contracts summarized on a quarterly basis were outstanding and recorded at estimated fair value: Weighted Weighted average WTI average volume CanadianPeriod (bpd) ($/bbl)October 1, 2011 to December 31, 2011 1,500 94.18January 1, 2012 to March 31, 2012 1,500 104.63April 1, 2012 to December 31, 2012 1,000 103.93----------------------------------------------------------------------------In 2011, these contracts had the following impact on the consolidated statements of operations and comprehensive loss: Three months ended Nine months ended September 30, September 30,(thousands of dollars) 2011 2010 2011 2010Realized gain (loss) on derivative contracts $ 871 $ - $ (353) $ -Unrealized gain on derivative contracts 6,350 - 11,166 - ------------------------ ------------------------- $ 7,221 $ - $ 10,813 $ -----------------------------------------------------------------------------In June 2011, as part of its risk management program, the Company entered into fixed price natural gas contracts to manage commodity price risk. The Company entered into physical contracts to sell 15,000 GJ per day of natural gas from July 1, 2011 to October 31, 2011 at an average AECO price of $4.06 per GJ. The Company does not mark-to-market physical sales contracts as they are not considered to be derivative instruments. These contracts will affect the price of the commodity sold during the period of the contract. The Company recognized a gain of $0.8 million on these contracts during the three and nine months ended September, 2011.Royalties. Royalties were 12.4% of revenue for the three months ended September 30, 2011 compared to 12.0% for the second quarter of 2011 and 8.8% for the three months ended September 30, 2010. The slight increase in the royalty rate from the second quarter is the result of more non-Crown wells coming on-stream with higher royalty rates. The Company received less gas cost allowance ("GCA") in the third quarter of 2011 compared to the same quarter of the previous year due to the decreased capital expenditures in natural gas related projects starting in 2010.Royalties as a percentage of revenue are highly sensitive to prices and adjustments to GCA and so royalty rates can fluctuate from quarter to quarter. In addition, when prices and corresponding revenues are lower, fixed monthly GCA becomes more significant to the overall royalty rate. Under the Alberta government's New Royalty Framework, producers will pay a reduced Crown royalty rate of 5% for the first year on up to 500 MMcf of gas production or up to 50 Mstb of oil production. In addition, for horizontal oil wells, based on the measured depth of the well, the Company will pay the Crown a 5% royalty for 24 to 30 months for up to 60 to 70 Mstb of oil production. The majority of the Company's horizontal program on Crown lands would qualify for the 30 months of 5% royalty for up to 70 Mstb of oil production. Three months ended Nine months ended September 30 September 30 2011 2010 2011 2010Gross Crown royalties 10.3% 12.0% 9.6% 13.0%Gas cost allowance (5.5%) (8.9%) (5.3%) (8.5%)Other royalties 7.6% 5.7% 6.9% 6.3% ------------------------- -------------------------Royalties 12.4% 8.8% 11.2% 10.8%Royalties ($/BOE) $ 5.24$ 2.48$ 4.64$ 3.37----------------------------------------------------------------------------Operating Expenses. Operating expenses are generally higher for oil projects when compared to gas projects. Accordingly, the increases in operating expenses noted below are largely due to increased oil production and decreased lower cost gas production per BOE.Operating expenses were $11.22 per BOE for the three months ended September 30, 2011 compared to $12.04 per BOE in the second quarter of 2011 and $9.45 per BOE in the third quarter of 2010. Operating expenses were $11.30 per BOE for the nine months ended September 30, 2011 compared to $9.96 per BOE in the first nine months of 2010. Operating expenses in the second quarter of 2011 were adversely affected by costs associated with temporary production and wet weather. The additional operating costs related to temporary oil production were mitigated in the third quarter of 2011 as these facilities were permanently connected to the new Garrington battery consolidation project and to a permanent battery installation in Willesden Green.Transportation Expenses. Transportation expenses were $0.89 per BOE for the three months ended September 30, 2011 compared to $0.66 per BOE in the second quarter of 2011 and $0.26 per BOE in the third quarter of 2010. Actual transportation costs for the first and second quarters of 2011 exceeded the amounts previously estimated by approximately $0.2 million. This excess was recorded in the third quarter of 2011, contributing approximately $0.25 per BOE to the reported expenses. Transportation expenses were $0.63 per BOE for the nine months ended September 30, 2011 compared to $0.19 per BOE in the first nine months of 2010. The increase in transportation expenses in 2011 relative to 2010 is the result of more clean oil trucking charges associated with higher 2011 oil production. In the first nine months of 2011, oil production was 21% of total production compared with 6% in the first nine months of 2010.OPERATING NETBACK(thousands of Three months ended Nine months ended dollars) September 30 September 30 2011 2010 2011 2010Revenue(1) $ 28,513 $ 18,928 $ 85,665 $ 62,511Realized gain (loss) on derivative contracts 871 - (353) -Royalties (3,543) (1,665) (9,636) (6,755)Operating expenses (7,590) (6,343) (23,473) (19,962)Transportation expenses (602) (172) (1,304) (387) -------------------------- -------------------------- $ 17,649 $ 10,748 $ 50,899 $ 35,407---------------------------------------------------------------------------Sales (MBOE) 676.3 670.9 2,077.6 2,004.5Per BOE Revenue(1) $ 42.16 $ 28.21 $ 41.23 $ 31.19 Realized gain (loss) on derivative contracts 1.29 - (0.17) - Royalties (5.24) (2.48) (4.64) (3.37) Operating expenses (11.22) (9.45) (11.30) (9.96) Transportation expenses (0.89) (0.26) (0.63) (0.19) -------------------------- -------------------------- $ 26.10 $ 16.02 $ 24.49 $ 17.67---------------------------------------------------------------------------(1) Includes royalty and other income classified with oil and gas sales.Excludes unrealized gain on derivative contracts of $6.4 million and $11.2million pertaining to fixed price crude oil swaps for the three and ninemonths ended September 30, 2011 respectively (September 30, 2010 - $Nil).General and Administrative Expenses. General and administrative expenses, excluding stock-based compensation, were $2.6 million or $3.81 per BOE for the three months ended September 30, 2011 compared to $2.0 million or $2.86 per BOE in the second quarter of 2011 and $2.0 million or $3.05 per BOE for the third quarter of 2010. General and administrative expenses, excluding stock-based compensation, were $7.2 million or $3.48 per BOE for the nine months ended September 30, 2011 compared to $6.0 million or $2.99 per BOE for the first nine months of 2010. General and administrative expenses increased in the third quarter of 2011 compared to the second quarter of 2011 as the result of a reduction in the amount of general and administrative expense capitalized. Gross general and administrative expenses increased for the nine months ended September 30, 2011 over 2010 due to increased salaries and bonus costs in 2011. Under IFRS, general and administrative expenses include share-based payments on the consolidated statement of operations and comprehensive income. IFRS also requires that the capitalization of general and administrative costs be limited to directly attributable costs. Capitalized general and administrative costs are limited to salaries and associated office rent of staff involved in capital activities. Under CGAAP, a reasonable allocation of general and administrative costs to property, plant and equipment was acceptable. As a result of the change in the capitalization criteria under IFRS, the Company increased its general and administrative costs by $0.1 million for the three months ended September 30, 2010 and by $0.4 million for the nine month ended September 30, 2010. The Company expects to have modestly higher general and administrative expenses in the future due to the adoption of IFRS. Three months ended Nine months ended September 30, September 30,(thousands of 2010 2010 dollars) 2011 (restated) 2011 (restated)General and administrative (gross) $ 3,747 $ 3,347 $ 11,440 $ 9,660Overhead recoveries (502) (412) (1,312) (1,181)Capitalized (671) (892) (2,895) (2,488) -------------------------- --------------------------General and administrative (cash) $ 2,574 $ 2,043 $ 7,233 $ 5,991Net stock-based compensation 239 382 730 785 -------------------------- --------------------------General and administrative (net) $ 2,813 $ 2,425 $ 7,963 $ 6,776--------------------------------------------------------------------------- General and administrative (cash) ($/BOE) $ 3.81 $ 3.05 $ 3.48 $ 2.99% Capitalized 18% 27% 25% 26%---------------------------------------------------------------------------Stock-Based Compensation. The Company accounts for stock-based compensation plans using the fair value method of accounting. Stock-based compensation costs were $0.4 million for the third quarter of 2011 ($0.2 million net of amounts capitalized) compared to $0.4 million in the second quarter of 2011 ($0.3 million net of amounts capitalized) and $0.5 million ($0.4 million net of amounts capitalized) in the third quarter of 2010. Stock-based compensation costs were $1.2 million for the first nine months of 2011 ($0.7 million net of amounts capitalized) versus $1.2 million ($0.8 million net of amounts capitalized) in the first nine months of 2010.Finance Expenses. Under IFRS, finance expenses include accretion on decommissioning obligations, accretion and interest on convertible debentures, as well as interest on bank loans. Previously under CGAAP, accretion on decommissioning obligations was included with depletion, depreciation and accretion. Finance expenses were $3.3 million for the third quarter of 2011, compared to $2.8 million in the second quarter of 2011 and $1.3 million in the third quarter of 2010. Finance expenses were $8.5 million for the nine months ended September 30, 2011, compared to $3.5 million in the comparable period of 2010. The increase in finance expenses from 2010 is the result of higher interest and accretion on the $96 million (principal) of convertible debentures issued on December 31, 2010 and June 8, 2011 at 7.5% and 7.25% respectively, and higher effective interest rates on bank loans, partially offset by lower average bank loan balances. There were no convertible debentures outstanding at September 30, 2010. The average effective interest rate on outstanding bank loans was 5.7% for the nine months ended September 30, 2011 compared to 4.9% for the comparable period in 2010. Three months ended Nine months ended September 30, September 30,(thousands of 2010 2010 dollars) 2011 (restated) 2011 (restated)Interest and accretion on convertible debentures $ 2,233 $ - $ 4,831 $ -Interest expense on credit facilities and other 670 836 2,394 2,254Accretion on decommissioning obligations 439 417 1,295 1,231 -------------------------- --------------------------Finance expenses $ 3,342 $ 1,253 $ 8,520 $ 3,485----------------------------------------------------------------------------Depletion and Depreciation. Depletion and depreciation was $12.3 million ($18.16 per BOE) for the third quarter of 2011 compared to $13.3 million ($18.90 per BOE) in the second quarter of 2011 and $10.6 million ($15.85 per BOE) in the third quarter of 2010. Depletion and depreciation was $38.0 million ($18.28 per BOE) for the first nine months of 2011 compared $32.4 million ($16.19 per BOE) for the comparable period in 2010. Decreased production in the third quarter of 2011 resulted in lower depletion and depreciation expense when compared to the second quarter of 2011.Impairment of property, plant and equipment. Under CGAAP, impairment of property, plant and equipment was assessed on the basis of an asset's estimated undiscounted future cash flows compared with the asset's carrying amount and if impairment was indicated, discounted cash flows were prepared to quantify the amount of the impairment. Under IFRS, impairment is assessed based on discounted cash flows compared with the asset's carrying amount to determine the recoverable amount and measure the amount of the impairment. In addition, under IFRS, the Company is required to perform its test at a cash generating unit ("CGU") level, which is the smallest identifiable grouping of assets that generates largely independent cash inflows. CGAAP impairment was based on undiscounted cash flows on a full cost centre basis. There is no requirement under IFRS to test for impairment at least annually as was done under CGAAP. Instead, IFRS requires that when there are indicators of impairment present, that an impairment test be performed. In addition, under IFRS, the Company must evaluate whether there are any changes in circumstances that would support an impairment reversal, which was not allowable under CGAAP. This may result in recoveries of previous impairments in future periods, net of depletion and depreciation.At January 1, 2010, the effective transition date to IFRS, the Company elected to use the IFRS 1 deemed cost exemption whereby the costs under CGAAP were allocated to CGUs based on reserves volumes and then tested for impairment. As a result, the Company recognized an impairment of $67.2 million at January 1, 2010 in the Shallow Gas CGU with a corresponding reduction in opening retained earnings. For the nine months ended September 30, 2010 and the year ended December 31, 2010 the Company recognized additional impairments of $111.0 million and $153.2 million respectively with a corresponding reduction in property, plant and equipment for the Shallow Gas, Deep Gas and Non-core CGUs due to declines in the future price forecasts used by the Company's independent qualified reserves evaluators for natural gas prices.At September 30, 2011, there were significant changes in the future commodity prices forecasts used by the Company's independent qualified reserves evaluators when compared to December 31, 2010. The Company considered the downward price adjustments on natural gas to be an indicator of impairment for the Company's Shallow Gas and Non-Core CGUs. Similarly, the Company considered the upward price adjustments on natural gas liquids to be an indicator of impairment reversal for its Deep Gas CGU as a result of this CGU having a significant amount of natural gas liquids. All of the Company's oil and gas reserves were evaluated and reported on by independent qualified reserves evaluators at September 30, 2011. Based on this assessment, the Company determined that its Shallow Gas and Non-Core CGUs were impaired by $3.2 million and $5.4 million respectively and that $9.7 million of previous impairments were reversed from its Deep Gas CGU as a result of this CGU having a significant amount of natural gas liquids. Under CGAAP, no impairments were recognized in prior periods.Decommissioning obligations. In the third quarter of 2011, the Company recorded an increase in decommissioning obligations of $6.8 million net of dispositions.Under IFRS, the decommissioning obligations are measured as the best estimate of the expenditure to be incurred and require that the decommissioning obligations be re-measured at the end of each reporting period using period-end discount rates. The risk-free discount rates used by the Company to re-measure the obligations at the end of the third quarter were reduced by between 0.67% and 1.41% depending on the timelines to reclamation as a result of changes in the Canadian bond market. The re-measurement of the obligation at the end of the third quarter of 2011 resulted in a $6.2 million increase to decommissioning obligations with an offsetting adjustment to property, plant and equipment.The Company also recorded $1.3 million in additional decommissioning obligations relating to current drilling activity and reduced decommissioning obligations by $1.0 million related to a property disposition in the third quarter of 2011. Accretion expense of $0.4 million for the third quarter of 2011 compared to $0.4 million in the second quarter of 2011 and $0.4 million in the third quarter of 2010 and was included in finance expenses.Income Taxes. Anderson is not currently taxable. The Company does not anticipate paying current income tax in 2011. The Company has approximately $473 million in tax pools at September 30, 2011.Funds from Operations. Funds from operations for the third quarter of 2011 were $12.7 million ($0.07 per share), 61% higher than the $7.9 million ($0.05 per share) recorded in the same period of 2010. This compares to funds from operations in the second quarter of 2011 of $13.9 million ($0.08 per share). Funds from operations for the first nine months of 2011 were $37.5 million ($0.22 per share) compared to $27.2 million ($0.16 per share) recorded in the same period of 2010. The increase in funds from operations in 2011 is a result of the Company's focus on oil prospects, which generate more funds from operations per BOE when compared to natural gas properties at current pricing. As new crude oil production is brought on-stream at higher expected operating margins, funds from operations are expected to increase. The changes in funds from operations as reported under IFRS for the three and nine months ended September 30, 2010 relate to the decrease in the capitalized general and administrative costs of $0.1 million and $0.4 million respectively from what was previously reported under CGAAP. Three months ended Nine months ended September 30 September 30 2010 2010(thousands of dollars) 2011 (restated) 2011 (restated)Cash from operating activities $ 11,893$ 8,287 $ 37,847 $ 29,844Changes in non-cash working capital 701 (823) (483) (4,041)Decommissioning expenditures 61 412 103 1,431 ----------------------- ------------------------Funds from operations $ 12,655$ 7,876 $ 37,467 $ 27,234---------------------------------------------------------------------------Earnings (loss). The Company reported earnings of $7.5 million in the third quarter of 2011 compared to earnings of $5.9 million for the second quarter of 2011 and a loss of $39.0 million for the third quarter of 2010. The Company reported earnings of $9.7 million in the first nine months of 2011 compared to a loss of $88.2 million in the comparable period in 2010. Earnings in the third quarter of 2011 are a result of the unrealized gain on derivative contracts along with increased oil production combined with higher oil and NGL prices. The 2010 three month loss was due to a $48.3 million impairment recorded in the period, while the 2010 nine month loss was due to a $111.0 million impairment recorded in the period.The Company's funds from operations and earnings are highly sensitive to changes in factors that are beyond its control. An estimate of the Company's sensitivities to changes in commodity prices, exchange rates and interest rates is summarized below:SENSITIVITIES Funds from Operations Earnings(thousands of dollars) Millions Per Share Millions Per Share$0.50/Mcf in price of natural gas $ 5.4 $ 0.03 $ 4.0 $ 0.02US $5.00/bbl in the WTI crude price $ 3.1 $ 0.02 $ 2.3 $ 0.01US $0.01 in the US/Cdn exchange rate $ 1.0 $ 0.01 $ 0.7 $ 0.001% in short-term interest rate $ 0.5 $ 0.00 $ 0.4 $ 0.00----------------------------------------------------------------------------This sensitivity analysis was calculated by applying different pricing, interest rate and exchange rate assumptions to the actual results for the twelve months ended September 30, 2011 related to production, prices excluding the impact of derivative contracts, royalty rates, operating costs and capital spending. As the Company changes its focus to crude oil development, the impact of oil prices is expected to become more significant and the impact of natural gas prices is expected to become less significant to funds from operations and earnings than is shown in the table above.CAPITAL EXPENDITURESThe Company spent $49.7 million on capital additions, net of proceeds on dispositions in the third quarter of 2011. The breakdown of expenditures is shown below: Three months ended Nine months ended September 30 September 30 2010 2010(thousands of dollars) 2011 (restated) 2011 (restated)Land, geological and geophysical costs $ 201$ 28 $ 3,967$ 625Acquisitions - 705 - 1,438Proceeds on disposition (6,203) (192) (11,570) (2,399)Drilling, completion and recompletion 43,700 30,548 95,260 53,537Drilling incentive credits (262) (1,003) (400) (3,617)Facilities and well equipment 11,436 7,910 28,001 33,782Capitalized G&A 671 892 2,895 2,488 ----------------------- -----------------------Total finding, development & acquisitionexpenditures 49,543 38,888 118,153 85,854 Change in compressor and other equipment inventory 128 480 128 (644)Office equipment and furniture 42 10 70 59 ----------------------- -----------------------Total net cash capital expenditures $ 49,713$ 39,378 $ 118,351$ 85,269----------------------------------------------------------------------------Drilling statistics are shown below: Three months ended Nine months ended September 30 September 30 2011 2010 2011 2010 Gross Net Gross Net Gross Net Gross NetGas - - 3 2.5 - - 23 19.0Oil 21 18.0 11 8.0 41 34.2 16 11.2Dry - - - - - - 4 2.8 ------------------------------------------------Total 21 18.0 14 10.5 41 34.2 43 33.0----------------------------------------------------------------------------Success rate (%) 100% 100% 100% 100% 100% 100% 91% 92%----------------------------------------------------------------------------During the third quarter of 2011, the Company drilled 21 gross (18.0 net capital, 16.4 net revenue) Cardium horizontal light oil wells. In addition, the Company brought 17 gross (13.4 net revenue) Cardium horizontal light wells on-stream. Approximately $11.4 million was spent on facilities and well equipment during the third quarter of 2011.In the third quarter of 2011, the Company sold 83 BOPD (89 BOED) of non-core, heavy oil production and other assets for proceeds of $6.2 million.RESERVESGLJ Petroleum Consultants ("GLJ"), an independent reserves evaluator, has completed an interim reserves report of all of the Company's oil & natural gas properties effective October 1, 2011, prepared in accordance with procedures and standards contained in the Canadian Oil and Gas Evaluation ("COGE") Handbook. The reserves definitions used in preparing the interim report are those contained in the COGE Handbook and the Canadian Securities Administrators National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities. This is not a year end reserves report. The October 1, 2011 report is the first step in a process and will be updated by GLJ for year end reserves reporting. At October 1, 2011, the Company's proved developed producing ("PDP"), total proved ("TP") and proved plus probable ("P&P") reserves were 12.4 MMBOE, 19.5 MMBOE and 35.8 MMBOE respectively.Oil now represents 18% of the Company's PDP, 15% of TP and 18% of the P&P reserves as compared to 11%, 11% and 12% respectively at December 31, 2010. The Company increased PDP, TP and P&P oil reserves by 72%, 28% and 62% in the previous nine months.SUMMARY OF OIL AND GAS RESERVES October 1, 2011 Before tax NPV Oil(1) NGL Gas(1) Total 10%(2) (Mbbls) (Mbbls) (MMcf) (MBOE) ($M)Proved developed producing 2,242 1,460 52,069 12,379 207,113Proved developed producing and proved developed non-producing 2,375 1,512 59,213 13,755 219,933Total proved 2,840 1,703 89,842 19,517 227,772Proved plus probable 6,334 3,185 157,525 35,773 349,575--------------------------------------------------------------------------- December 31, 2010 Before tax NPV Oil(1) NGL Gas(1) Total 10%(2) (Mbbls) (Mbbls) (MMcf) (MBOE) ($M)Proved developed producing 1,303 1,376 52,498 11,428 166,058Proved developed producing and proved developed non-producing 1,471 1,426 59,955 12,889 175,619Total proved 2,226 1,673 97,313 20,117 184,248Proved plus probable 3,908 2,676 150,621 31,687 271,469---------------------------------------------------------------------------(1) Coal Bed Methane is not material to report separately and is included inthe Natural Gas category. Heavy Oil is not material to report separately andis included in the Oil category.(2) The estimated net present value of future net revenues presented in thetable above does not necessarily represent the fair market value of theCompany's reserves.SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONSAs at October 1, 2011GLJ Forecast Prices and Costs Oil Natural Gas Edmonton Liquids Prices Light, Sweet Crude AECO Gas Pentanes WTI Cushing Edmonton Price Propane Butane PlusYear ($US/bbl) ($Cdn/bbl) ($Cdn/Mcf) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl)2011 Q4 85.00 91.84 3.90 55.10 70.71 100.102012 90.00 94.39 4.36 59.46 72.68 97.222013 95.00 96.94 4.59 61.07 74.64 98.882014 100.00 101.02 5.05 63.64 77.79 103.042015 100.00 101.02 5.51 63.64 77.79 103.042016 100.00 101.02 5.97 63.64 77.79 103.042017 101.36 102.41 6.43 64.52 78.85 104.462018 103.38 104.47 6.86 65.82 80.44 106.562019 105.45 106.58 7.00 67.15 82.07 108.712020 107.56 108.73 7.14 68.50 83.73 110.91Thereafter 2%----------------------------------------------------------------------------SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONSAs at October 1, 2011GLJ Forecast Prices and Costs Exchange Inflation rateYear Rate % (US$/Cdn)2011 Q4 2.0 0.982012 2.0 0.982013 2.0 0.982014 2.0 0.982015 2.0 0.982016 2.0 0.982017 2.0 0.982018 2.0 0.982019 2.0 0.982020 2.0 0.98Thereafter 2%--------------------------------SHARE INFORMATIONThe Company's shares have been listed on the Toronto Stock Exchange since September 7, 2005 under the symbol "AXL". As of November 14, 2011, there were 172.5 million common shares outstanding, 14.3 million stock options outstanding, $50.0 million principal amount of convertible debentures which are convertible into common shares at a conversion price of $1.55 per common share and $46.0 million principal amount of convertible debentures which are convertible into common shares at a conversion price of $1.70 per common share. There were no common shares issued in the third quarter of 2011 or the third quarter of 2010 under the employee stock option plan. Three months ended Nine months ended September 30 September 30 2011 2010 2011 2010High $ 0.87 $ 1.24 $ 1.36 $ 1.57Low $ 0.42 $ 0.95 $ 0.42 $ 0.95Close $ 0.43 $ 1.12 $ 0.43 $ 1.12Volume 23,739,995 18,034,164 108,708,081 88,346,700Shares outstanding at September 30 172,549,701 172,400,401 172,549,701 172,400,401Market capitalization at September 30 $ 74,196,371 $ 193,088,449 $ 74,196,371 $ 193,088,449----------------------------------------------------------------------------The statistics above include trading on the Toronto Stock Exchange only. Shares also trade on alternative platforms like Alpha, Chi-X, Pure and Omega. During the three and nine months ended September 30, 2011, approximately 11.6 million and 77.3 million common shares traded on these alternative exchanges respectively.ELIMINATION OF DEFICITOn May 16, 2011 the Company's shareholders approved an ordinary resolution to eliminate the Company's accumulated deficit at January 1, 2011 against share capital without reduction to stated capital or paid up capital. The Company's accumulated deficit at January 1, 2011 was largely the result of the implementation of IFRS combined with the significant reduction in natural gas prices in recent years which reduced profitability and resulted in write downs of historical costs. The Company believes that the elimination of the consolidated accounting deficit, in connection with the implementation of IFRS, is beneficial on a go-forward basis. The accounting adjustment should allow shareholders to better evaluate the Company's performance under IFRS reporting as well as measure the success of the Company's response to detrimental changes in the natural gas business by transitioning to a more oil-weighted company.LIQUIDITY AND CAPITAL RESOURCESAt September 30, 2011, the Company had outstanding long-term bank loans of $51.8 million, convertible debentures of $96.0 million (principal) and a working capital deficiency of $56.7 million, excluding the unrealized gain on derivative contracts. The working capital deficiency is due to accruals associated with the capital program. The following table shows the changes in bank loans plus cash working capital deficiency: Three months ended Nine months ended September 30 September 30 2010 2010(thousands of dollars) 2011 (restated) 2011 (restated)Bank loans plus cash working capital deficiency, beginning of period $ (71,464) $ (70,284) $ (71,507) $ (72,524)Funds from operations 12,655 7,876 37,467 27,234Net cash capital expenditures (49,713) (39,378) (118,351) (85,269)Proceeds from issue of convertible debentures, net of issue costs - - 43,860 -Proceeds from issue of share capital, net of issue costs - - - 29,792Proceeds from exercise of stock options - - 51 -Decommissioning expenditures (61) (412) (103) (1,431) ------------------------- -------------------------Bank loans plus cash working capital deficiency, end of period $ (108,583) $ (102,198) $ (108,583) $ (102,198)----------------------------------------------------------------------------The Board of Directors approved an increase to the Company's 2011 capital budget to $145 million, net of dispositions, of which $118.4 million was spent in the first nine months of 2011. The Company was committed to drill 74 Edmonton Sands gas wells under its farm-in agreement by March 31, 2012. In October 2011, the commitment date was extended to March 31, 2013. The Company does not plan to drill any additional Edmonton Sands gas wells until after 2012. The Company now plans to drill 51 gross (44.3 net capital, 39.1 net revenue) Cardium oil wells in 2011, of which 40 gross (34.1 net capital, 30.2 net revenue) have been drilled to date in 2011.The Company's need for capital will be both short-term and long-term in nature. Short-term capital is required to finance accounts receivable and other similar short-term assets while the acquisition and development of oil and natural gas properties requires larger amounts of long-term capital. At September 30, 2011, the Company had total credit facilities of $135 million and $83.0 million of credit available under these facilities. On June 8, 2011, the Company completed a convertible subordinated debenture financing for proceeds, net of commission and expenses, of $43.9 million. The net proceeds were initially used to pay down bank debt. The availability created in the credit facilities, along with cash flows, will be prudently used to finance the Company's 2011 and 2012 capital programs. The available lending limits under the bank facilities are reviewed twice a year and are based on the bank syndicate's interpretation of the Company's reserves and future commodity prices. The bank syndicate is currently reviewing the Company's credit facilities and is scheduled to be completed by the end of November 2011. While the Company does not anticipate any changes to the total amounts available under the credit facilities, there can be no assurance that the amounts available or the applicable margins will not be adjusted. As the Company plans to fund its 2012 capital program from a combination of cash flow, existing credit facilities and asset dispositions, oil and natural gas prices will impact the level of capital spending in 2012.CONTRACTUAL OBLIGATIONSThe Company enters into various contractual obligations in the course of conducting its operations. These obligations include:-- Loan agreements - The reserves-based extendible, revolving term credit facility and working capital credit facility have a revolving period ending on July 11, 2012, extendible at the option of the lenders. If not extended, the facilities cease to revolve and all outstanding advances thereunder become repayable one year from the term date of July 11, 2012. The supplemental facility is available on a revolving basis and expires on July 11, 2012 with any amounts outstanding due in full at that time. No amounts were drawn under the supplemental facility at September 30, 2011.-- Convertible debentures - The Company has $96.0 million (principal) in convertible debentures outstanding at September 30, 2011, of which $50.0 million bears interest at 7.5% ("Series A Convertible Debentures") and $46.0 million bears interest at 7.25% ("Series B Convertible Debentures"). The convertible debentures have a face value of $1,000 with interest payable semi-annually. The Series A Convertible Debentures mature on January 31, 2016 with interest payable on the last day of July and January, commencing July 31, 2011. These convertible debentures are convertible at the holder's option at a conversion price of $1.55 per common share, subject to adjustment in certain events and are not redeemable by the Company before January 31, 2014. The Series B Convertible Debentures mature on June 30, 2017 with interest payable on the last day of June and December, commencing December 31, 2011. These convertible debentures are convertible at the holder's option at a conversion price of $1.70 per common share, subject to adjustment in certain events and are not redeemable by the Company before June 30, 2014.-- Lease for office space - This lease expires on November 30, 2012. Future minimum lease payments are expected to be $0.5 million for the remainder of 2011, and $1.6 million in 2012.-- Firm service transportation commitments - The Company has entered into firm service transportation agreements for approximately 23 million cubic feet per day of gas sales for various terms expiring between 2011 and 2020. Based on rate schedules announced to date, the payments in each of the next five years and thereafter are estimated to be $0.4 million for the remainder of 2011, $1.3 million in 2012, $0.9 million in 2013, $0.7 million in 2014, $0.6 million in 2015 and $0.4 million thereafter.-- Oil transportation contract - In 2010, the Company entered into a facilities construction and operation agreement pursuant to which it is committed to ship a minimum volume of gross crude oil through new facilities and pipelines being constructed in Garrington. The total financial commitment is $2.6 million to be incurred over a minimum of five years. The contract contains a minimum volume requirement per year for the first five years following completion of construction which was completed in October 2011. In the event that the volume shipped is less than the minimum volume, the Company will be subject to a fee per cubic metre of oil on the difference between actual volumes shipped and the minimum volume required. Conversely, if the Company exceeds the minimum volume requirement in a single year, the excess is carried forward as a credit to the minimum volume requirement in the subsequent year. If no volumes were shipped, the minimum of $0.26 million would be payable each year. After the total contracted volumes have been shipped, the contract will automatically renew for one year periods unless terminated.-- Farm-in - On January 30, 2009, the Company announced a farm-in agreement with a large international oil and gas company on lands near its existing core operations. Under the farm-in agreement, the Company has access to 388 gross (205 net) sections of land. During the commitment phase of the transaction, the Company is committed to drill, complete and equip 200 wells to earn an interest in up to 120 sections. The Company has drilled 126 wells under the commitment to September 30, 2011. The Company is obligated to complete the drilling of the remaining wells on or before March 31, 2013. The commitment is subject to certain guarantees. The Company estimates that its minimum commitment to drill the remaining 74 wells is $10 million. The Company currently plans to defer its spending on the farm-in project until after 2012.These obligations are described further in note 15 to the interim consolidated financial statements for the three and nine months ended September 30, 2011 and 2010.INTERNATIONAL FINANCIAL REPORTING STANDARDSThe Company adopted IFRS effective January 1, 2011. As a result, the Company's financial results for the nine months ended September 30, 2011 and comparative periods are reported under IFRS while selected historical data before 2010 continues to be reported under previous CGAAP. (Refer to note 17 of the interim consolidated financial statements for the period ended March 31, 2011 note 16 for the period ended September 30, 2011 for the Company's assessment of the impacts of the transition to IFRS).NEW AND PENDING ACCOUNTING STANDARDSThe Company is currently evaluating the impact of new and pending accounting standards.IFRS 9 - Financial Instruments. In November 2009, the IASB published IFRS 9 "Financial Instruments" which covers the classification and measurement of financial assets as part of its project to replace IAS 39 "Financial Instruments: Recognition and Measurement." IFRS 9 uses a single approach to determine whether a financial asset is measured at amortized cost or fair value, replacing the multiple rules in IAS 39. The approach in IFRS 9 is based on how an entity managed its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets. The new standard also requires a single impairment method to be used, replacing the multiple impairment methods in IAS 39.In October 2010, additional requirements for classifying and measuring financial liabilities were added to IFRS 9. Under this guidance, entities have the option to recognize financial liabilities at fair value through profit or loss. If this option is elected, entities would be required to reverse the portion of the fair value change due to own credit risk out of profit or loss and recognize the change in other comprehensive income.On August 4, 2011, the IASB issued an exposure draft proposing to change the mandatory effective date of IFRS 9 to annual periods beginning on or after January 1, 2015 from the original effective date of January 1, 2013. Early adoption is permitted and the standard is required to be applied retrospectively. The comment period for this exposure draft closed on October 21, 2011. The implementation of the issued standard is not expected to have a significant impact on the Company's financial position or results.Reporting Entity. In May 2011, the IASB issued IFRS 10 Consolidated Financial Statement, IFRS 11 Joint Arrangements, IFRS 12 Disclosures of Interests in Other Entities, and amendments to IAS 27 Separate Financial Statements and IAS 28 Investments in Associates and Joint Ventures.IFRS 10 creates a single consolidation model by revising the definition of control in order to apply the same control criteria to all types of entities, including joint arrangements, associates and special purpose vehicles. IFRS 11 establishes a principle-based approach to the accounting for joint arrangements by focusing on the rights and obligations of the arrangement and limits the application of proportionate consolidation accounting to arrangements that meet the definition of a joint operation.IFRS 12 is a comprehensive disclosure standard for all forms of interests in other entities, including joint arrangements, associates and special purpose vehicles.Retrospective application of these standards with relief for certain transactions is effective for fiscal years beginning on or after January 1, 2013, with earlier application permitted if all five standards are collectively adopted.IFRS 13 - Fair Value Measurement. In May 2011, the IASB issued IFRS 13 Fair Value Measurement, which establishes a single source of guidance for all fair value measurements; clarifies the definition of fair value; and enhances the disclosures on fair value measurement. Prospective application of this standard is effective for fiscal years beginning on or after January 1, 2013, with early application permitted.IAS 12 - Income Taxes. IAS 12 "Income Taxes" was amended on December 20, 2010 to remove subjectivity in determining on which basis an entity measures the deferred tax relating to an asset. The amendment introduces a presumption that an entity will assess whether the carrying value of an asset will be recovered through the sale of the asset. The amendment to IAS 12 is effective for reporting periods beginning on or after January 1, 2012.CONTROLS AND PROCEDURESThe Chief Executive Officer ("CEO") and the Chief Financial Officer ("CFO") have designed, or caused to be designed under their supervision, disclosure controls and procedures ("DC&P) and internal controls over financial reporting ("ICOFR") as defined in National Instrument 52-109 Certification of Disclosure in Issuer's Annual and Interim Filings in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with IFRS.The DC&P have been designed to provide reasonable assurance that material information relating to the Company is made known to the CEO and CFO by others and that information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by the Company under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation. The Company's CEO and CFO have concluded, based on their evaluation as of the end of the period covered by the interim filings, that the Company's disclosure controls and procedures are effective to provide reasonable assurance that material information related to the issuer is made known to them by others within the Company.The CEO and CFO are required to cause the Company to disclose any change in the Company's ICOFR that occurred during the most recent interim period that has materially affected, or is reasonably likely to materially affect, the Company's ICOFR. No changes in ICOFR were identified during such period that have materially affected or are reasonably likely to materially affect the Company's ICOFR. There were no changes to ICOFR as a result of the transition to IFRS.It should be noted a control system, including the Company's DC&P and ICOFR, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objective of the control system will be met and it should not be expected that DC&P and ICOFR will prevent all errors or fraud.BUSINESS RISKSOil and gas exploration and production is capital intensive and involves a number of business risks including, without limitation, the uncertainty of finding new reserves, the instability of commodity prices, weather and various operational risks. Commodity prices are influenced by local and worldwide supply and demand, OPEC actions, ongoing global economic concerns, the U.S. dollar exchange rate, transportation costs, political stability and seasonal and weather related changes to demand. The price of natural gas has weakened due to increasing U.S. gas production driven primarily by the U.S. shale gas plays. The large amount of gas in storage combined with strong U.S. gas production and financial market fears has continued to suppress the price of natural gas. Oil prices had increased earlier this year, and continue to remain volatile as they are a geopolitical commodity, affected by concerns about economic markets in the U.S. and Europe and continued instability in oil producing countries. The industry is subject to extensive governmental regulation with respect to the environment. Operational risks include well performance, uncertainties inherent in estimating reserves, timing of/ability to obtain drilling licences and other regulatory approvals, ability to obtain equipment, expiration of licences and leases, competition from other producers, sufficiency of insurance, ability to manage growth, reliance on key personnel, third party credit risk and appropriateness of accounting estimates. These risks are described in more detail in the Company's Annual Information Form for the year ended December 31, 2010 filed with Canadian securities regulatory authorities on SEDAR.The Company anticipates making substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future. As the Company's revenues may decline as a result of decreased commodity pricing, it may be required to reduce capital expenditures. In addition, uncertain levels of near term industry activity coupled with the present global economic concerns exposes the Company to additional access to capital risk. There can be no assurance that debt or equity financing, or funds generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Company. The inability of the Company to access sufficient capital for its operations could have a material adverse effect on the Company's business, financial condition, results of operations and prospects.Anderson manages these risks by employing competent professional staff, following sound operating practices and using capital prudently. The Company generates its exploration prospects internally and performs extensive geological, geophysical, engineering, and environmental analysis before committing to the drilling of new prospects. Anderson seeks out and employs new technologies where possible. With the Company's extensive drilling inventory and advance planning, the Company believes it can manage the slower pace of regulatory approvals and the requirements for extensive landowner consultation.The Company has a formal emergency response plan which details the procedures employees and contractors will follow in the event of an operational emergency. The emergency response plan is designed to respond to emergencies in an organized and timely manner so that the safety of employees, contractors, residents in the vicinity of field operations, the general public and the environment are protected. A corporate safety program covers hazard identification and control on the jobsite, establishes Company policies, rules and work procedures and outlines training requirements for employees and contract personnel.The Company currently deals with a small number of buyers and sales contracts, and endeavors to ensure that those buyers are an appropriate credit risk. The Company continuously evaluates the merits of entering into fixed price or financial hedge contracts for price management.The oil and natural gas business is subject to regulation and intervention by governments in such matters as the awarding of exploration and production interests, the imposition of specific drilling obligations, environmental protection controls, control over the development and abandonment of fields (including restrictions on production) and possibly expropriation or cancellation of contract rights. As well, governments may regulate or intervene with respect to prices, taxes, royalties and the exportation of oil and natural gas. Such regulation may be changed from time to time in response to economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for oil and natural gas, increase the Company's costs or affect its future opportunities.The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation. Such legislation provides for restrictions and prohibitions on the release or emission of various substances produced in association with certain oil and gas industry operations. Such legislation may also impose restrictions and prohibitions on water use or processing in connection with certain oil and gas operations. In addition, such legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with such legislation can require significant expenditures and a breach of such requirements may result, amongst other things in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage, and the imposition of material fines and penalties.The Government of Alberta implemented a new oil and gas royalty framework effective January 2009. The new framework establishes new royalties for conventional oil, natural gas and bitumen that are linked to price and production levels and apply to both new and existing conventional oil and gas activities and oil sands projects. Under the framework, the formula for conventional oil and natural gas royalties uses a sliding rate formula, dependent on the market price and production volumes. On March 3, 2009, June 11, 2009 and June 25, 2009, the Government of Alberta announced amendments to the framework. This incentive program included a drilling credit for new oil and natural gas wells drilled between April 1, 2009 and March 31, 2011, providing a $200 per metre drilled royalty credit to companies. The credit was used to offset up to 50% of Crown royalties paid after the wells have been drilled up until March 31, 2011. There is also a new well incentive program that provides a maximum 5% royalty rate for the first 12 months of production from new wells that begin producing oil or natural gas between April 1, 2009 and March 31, 2011 to a maximum of 50,000 barrels of oil or 500 million cubic feet of natural gas.On March 11, 2010, the Alberta government announced its intention to adjust royalty rates effective January 1, 2011. This adjustment included making the incentive program royalty rate of 5% on new natural gas and conventional oil wells a permanent feature of the royalty system with the time and volume limits discussed above. The maximum royalty rate was reduced from 50% to 40% for conventional oil and to 36% for natural gas.Changes to the royalty regime in the Province of Alberta are subject to certain risks and uncertainties. There may be modifications introduced to the royalty structure and such changes may be adverse to the business of the Company. There can be no assurance that the Government of Alberta or the Government of Canada will not adopt new royalty regimes which may render the Company's projects uneconomic or otherwise adversely affect the business of the Company.BUSINESS PROSPECTSThe Company believes it has an excellent future drilling inventory in the Cardium light oil horizontal oil play and is focused on growing its production and reserves with Cardium horizontal drilling. The Company has 124.5 gross (74.0 net) sections in the Cardium fairway and has identified an inventory of 204 gross (129.8 net revenue) drill ready Cardium horizontal oil locations, of which 62 gross (45.6 net revenue) have been drilled to September 30, 2011. The Company continues to add to its land position and drilling inventory through a combination of acquisitions, property swaps and farm-ins, and continues to implement new technologies to control and reduce its costs in this project.The Company's goal is to grow its oil production to achieve 50% of total production from oil and NGL by sometime in 2012. The capital budget for 2011 is $145 million and annual production guidance for 2011 is between 7,500 and 8,000 BOED. The Company could have considered a budget which yielded higher BOED production growth through spending on natural gas prospects, but elected to proceed with a 100% oil capital budget which has not created BOED production growth, but has yielded substantially higher cash flows through stronger netbacks.Risks associated with the production guidance provided include continued low commodity prices which may restrict capital spending, new well performance, gas plant capacity, gas plant turnaround duration, regulatory issues, weather problems and access to industry services.QUARTERLY INFORMATIONThe following table provides financial and operating results for the last eight quarters. Commodity prices remain volatile, affecting funds from operations and earnings throughout those quarters. In 2010, the Company changed its focus to oil projects in light of the continued depressed natural gas market, and suspended its shallow gas drilling program until natural gas prices improve. Revenues, funds from operations and earnings (loss) over the past three quarters reflect the benefits from increased sales of crude oil volumes. Also, earnings were affected in each of the four quarters in 2010 by impairments in the value of property, plant and equipment related to natural gas and natural gas liquids reserves values. With the volatility in commodity prices, in the third quarter of 2011 a portion of previously recognized impairments were reversed and additional impairments taken. Earnings were also affected in the third quarter of 2011 by hedging gains and gains on the sale of assets.Note that the quarterly table contains both IFRS and CGAAP numbers. Comparatives before 2010 have not been restated to reflect the changes in accounting policies as a result of adopting IFRS.SELECTED QUARTERLY INFORMATION($ amounts in thousands, except per share amounts and prices) IFRS Q4 2010 Q3 2011 Q2 2011 Q1 2011 (restated) ----------------------------------------------------Revenue, net of royalties $ 24,970 $ 27,776 $ 23,283 $ 21,690Funds from operations $ 12,655 $ 13,944 $ 10,868 $ 9,282Funds from operations per share, basic and diluted $ 0.07 $ 0.08 $ 0.06 $ 0.05Earnings (loss) before effect of impairments or reversals thereof $ 6,667 $ 5,932 $ (3,681) $ (4,864)Earnings (loss) per share before effect of impairments or reversals thereof Basic and diluted $ 0.04 $ 0.03 $ (0.02) $ (0.03)Earnings (loss) $ 7,472 $ 5,932 $ (3,681) $ (36,545) Basic and diluted $ 0.04 $ 0.03 $ (0.02) $ (0.21)Capital expenditures, including acquisitions net of dispositions $ 49,713 $ 26,284 $ 42,354 $ 26,240Cash from operating activities $ 11,893 $ 14,953 $ 11,001 $ 10,489Daily sales Natural gas (Mcfd) 30,038 31,990 33,931 38,479 Oil (bpd) 1,709 1,759 1,372 992 NGL (bpd) 636 667 699 823 BOE (BOED) 7,351 7,758 7,726 8,228Average prices Natural gas ($/Mcf) $ 3.85 $ 3.79 $ 3.58 $ 3.48 Oil ($/bbl) $ 89.05 $ 99.39 $ 84.71 $ 77.62 NGL ($/bbl) $ 66.07 $ 74.24 $ 65.97 $ 58.87 BOE ($/BOE)(i) $ 42.16 $ 44.71 $ 36.80 $ 31.63---------------------------------------------------------------------------- IFRS CGAAP---------------------------------------------------------------------------- Q3 2010 Q2 2010 Q1 2010 (restated) (restated) (restated) Q4 2009 ----------- ----------- ----------- -----------Revenue, net of royalties $ 17,263 $ 18,622 $ 19,871 $ 18,708Funds from operations $ 7,876 $ 8,923 $ 10,435 $ 9,151Funds from operations per share, basic and diluted $ 0.05 $ 0.05 $ 0.06 $ 0.06Earnings (loss) before effect of impairment $ (3,057) $ (2,450) $ 256 $ (6,457)Earnings (loss) per share before effect of impairment Basic and diluted $ (0.02) $ (0.01) $ - $ (0.04)Loss $ (39,029) $ (4,769) $ (44,444) $ (6,457)Loss per share, basic and diluted $ (0.23) $ (0.03) $ (0.27) $ (0.04)Capital expenditures, including acquisitions net of dispositions $ 39,378 $ 12,664 $ 33,227 $ 11,312Cash from operating activities $ 8,287 $ 8,811 $ 12,746 $ 5,361Daily sales Natural gas (Mcfd) 35,778 38,998 35,221 34,938 Oil (bpd) 568 491 345 351 NGL (bpd) 761 741 785 906 BOE (BOED) 7,292 7,732 7,000 7,080Average prices Natural gas ($/Mcf) $ 3.43 $ 3.78 $ 5.22 $ 4.28 Oil ($/bbl) $ 68.24 $ 70.45 $ 75.47 $ 69.60 NGL ($/bbl) $ 51.41 $ 53.55 $ 56.68 $ 47.67 BOE ($/BOE)(i) $ 28.21 $ 28.88 $ 36.93 $ 31.38----------------------------------------------------------------------------(i) Includes royalty and other income classified with oil and gas sales andexcludes realized and unrealized gains and losses on derivative contracts.FORWARD-LOOKING STATEMENTSCertain statements in this news release including, without limitation, management's assessment of future plans and operations; benefits and valuation of the development prospects described herein; number of locations in drilling inventory and wells to be drilled; timing and location of drilling and tie-in of wells and the costs thereof; productive capacity of the wells; timing of and construction of facilities; expected production rates; percentage of production from oil and natural gas liquids; dates of commencement of production; amount of capital expenditures and the timing and method of financing thereof; value of undeveloped land; extent of reserves additions; ability to attain cost savings; drilling program success; impact of changes in commodity prices on operating results; impact of changes in the royalty regime applicable to the Company; estimates of future revenues, costs, netbacks, funds from operations and debt levels; commodity price outlook and general economic outlook may constitute "forward-looking information" (within the meaning of applicable Canadian securities legislation) or "forward-looking statements" (within the meaning of the United States Private Securities Litigation Reform Act of 1995, as amended) and necessarily involve risks and assumptions made by management of the Company including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation; loss of markets; volatility of commodity prices; currency fluctuations; imprecision of reserves estimates; environmental risks; competition from other producers; inability to retain drilling rigs and other services; adequate weather to conduct operations; sufficiency of budgeted capital, operating and other costs to carry out planned activities;wells not performing as expected; incorrect assessment of the value of acquisitions and farm-ins; failure to realize the anticipated benefits of acquisitions and farm-ins; delays resulting from or inability to obtain required regulatory approvals; changes to government regulation; ability to access sufficient capital from internal and external sources; and other factors, many of which are beyond the Company's control. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as the factors are interdependent, and management's future course of action would depend on its assessment of all information at the time. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements and readers should not place undue reliance on the assumptions and forward-looking statements. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect Anderson's operations and financial results are included in reports on file with Canadian and U.S. securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), the EDGAR website (www.sec.gov/edgar) or at Anderson's website (www.andersonenergy.ca).Estimates of future revenues, costs, netbacks, funds from operations and debt levels may constitute future oriented financial information or a financial outlook under applicable securities laws, and are presented to provide readers with a comparison to levels in 2009 and 2010 based on the various assumptions described or inherent in the estimates. Readers are cautioned that the information may not be appropriate for other purposes.This news release contains information regarding forecasts that were obtained from reports prepared by third parties. None of the authors of such reports have provided any form of consultation, advice or counsel regarding any aspect of this news release. Actual outcomes may vary materially from the forecast in such reports, and the prospect for material variation can be expected to increase as the length of the forecast period increases.The forward-looking statements contained in this news release are made as at the date of this news release and the Company does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.CONVERSIONDisclosure provided herein in respect of barrels of oil equivalent (BOE) may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.ANDERSON ENERGY LTD.Consolidated Statements of Financial Position(Stated in thousands of dollars)(Unaudited) September 30, December 31, 2011 2010ASSETSCurrent assets: Cash and cash equivalents $ -$ 4,024 Accounts receivable and accruals (note 13) 16,135 20,998 Prepaid expenses and deposits 2,689 3,052 Current portion of unrealized gain on derivative contracts (note 13) 7,551 - -------------- -------------- 26,375 28,074Deferred taxes 24,493 29,657Unrealized gain on derivative contracts (note 13) 1,697 -Property, plant and equipment (notes 4 and 5) 414,498 320,673 -------------- -------------- $ 467,063$ 378,404------------------------------------------------------------------------------------------------------------------------------------------------------LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities: Accounts payable and accruals $ 75,560$ 46,862 Unrealized loss on derivative contracts (note 13) - 1,918 -------------- -------------- 75,560 48,780Bank loans (note 6) 51,847 52,719Convertible debentures (note 7) 84,334 43,460Decommissioning obligations (note 8) 60,071 51,550 -------------- -------------- 271,812 196,509Shareholders' equity: Share capital (note 9) 171,460 426,925 Equity component of convertible debentures (note 7) 5,019 2,592 Contributed surplus 9,049 7,921 Retained earnings (deficit) (note 9) 9,723 (255,543) -------------- -------------- 195,251 181,895Commitments (note 15)Subsequent event (note 15) -------------- -------------- $ 467,063$ 378,404------------------------------------------------------------------------------------------------------------------------------------------------------See accompanying notes to the consolidated financial statements.ANDERSON ENERGY LTD.Consolidated Statements of Operations and Comprehensive Income (Loss)(Stated in thousands of dollars, except per share amounts)(Unaudited) Three months ended Nine months ended September 30, September 30, 2010 2010 2011 (note 16) 2011 (note 16)Oil and gas sales $ 28,513 $ 18,928 $ 85,665 $ 62,511Royalties (3,543) (1,665) (9,636) (6,755) ----------- ----------- ----------- -----------Revenue, net of royalties 24,970 17,263 76,029 55,756Realized gain (loss) on derivative contracts 871 - (353) -Unrealized gain on derivative contracts 6,350 - 11,166 -Gain (loss) on sale of property, plant and equipment 3,476 (388) 4,622 320 ----------- ----------- ----------- ----------- 35,667 16,875 91,464 56,076Operating expenses 7,590 6,343 23,473 19,962Transportation expenses 602 172 1,304 387Depletion and depreciation 12,280 10,631 37,976 32,443Impairment loss (reversal) on property, plant and equipment (note 5) (1,074) 48,317 (1,074) 110,969General and administrative expenses 2,813 2,425 7,963 6,776 ----------- ----------- ----------- -----------Earnings (loss) from operating activities 13,456 (51,013) 21,822 (114,461)Finance income (note 11) 21 8 54 72Finance expenses (note 11) (3,342) (1,253) (8,520) (3,485) ----------- ----------- ----------- -----------Net finance expenses (3,321) (1,245) (8,466) (3,413)Earnings (loss) before taxes 10,135 (52,258) 13,356 (117,874)Deferred income tax expense (benefit) 2,663 (13,229) 3,633 (29,632) ----------- ----------- ----------- -----------Earnings (loss) and comprehensive income (loss) for the period $ 7,472 $ (39,029) $ 9,723 $ (88,242)---------------------------------------------------------------------------Basic and diluted earnings (loss) per share(note 10) $ 0.04 $ (0.23) $ 0.06 $ (0.52)---------------------------------------------------------------------------See accompanying notes to the consolidated financial statements.ANDERSON ENERGY LTD.Consolidated Statements of Changes in Shareholders' Equity(Stated in thousands of dollars, except number of common shares)(Unaudited) Equity component of Number of convertible Common Shares Share capital debenturesBalance at January 1, 2010 150,500,401 $ 396,524 $ -Issued pursuant to prospectus (note 9) 21,900,000 31,755 -Share issue costs, net of tax of $0.5 million - (1,456) -Share-based payments - - -Loss for the period - - - ---------------- ---------------- ----------------Balance at September 30, 2010 (note 16) 172,400,401 426,823 --------------------------------------------------------------------Balance at January 1, 2011 172,485,301 426,925 2,592Elimination of deficit (note 9) - (255,543) -Equity component of convertible debentures, net of tax of $1.5 million (note 7) - - 2,427Share-based payments - - -Options exercised 64,400 78 -Earnings for the period - - - ---------------- ---------------- ----------------Balance at September 30, 2011 172,549,701 $ 171,460 $ 5,019-------------------------------------------------------------------ANDERSON ENERGY LTD.Consolidated Statements of Changes in Shareholders' Equity(Stated in thousands of dollars, except number of common shares)(Unaudited) Retained Total Contributed earnings shareholders surplus (deficit) ' equityBalance at January 1, 2010 6,338 $ (130,756) $ 272,106Issued pursuant to prospectus (note 9) - - 31,755Share issue costs, net of tax of $0.5 million - - (1,456)Share-based payments 1,226 - 1,226Loss for the period - (88,242) (88,242) --------------- ------------- -------------Balance at September 30, 2010 (note 16) 7,564 (218,998) 215,389-------------------------------------------------------------Balance at January 1, 2011 7,921 (255,543) 181,895Elimination of deficit (note 9) - 255,543 -Equity component of convertible debentures, net of tax of $1.5 million (note 7) - - 2,427Share-based payments 1,155 - 1,155Options exercised (27) - 51Earnings for the period - 9,723 9,723 --------------- ------------- -------------Balance at September 30, 2011 $ 9,049 $ 9,723 $ 195,251-------------------------------------------------------------See accompanying notes to the consolidated financial statements.ANDERSON ENERGY LTD.Consolidated Statements of Cash FlowsNINE MONTHS ENDED SEPTEMBER 30, 2011 AND 2010 (Stated in thousands of dollars)(Unaudited) 2011 2010 (note 16)CASH PROVIDED BY (USED IN)OPERATIONSEarnings (loss) for the period $ 9,723 $ (88,242)Adjustments for: Depletion and depreciation 37,976 32,443 Unrealized gain on derivative contracts (11,166) - Impairment loss (reversal) on property, plant and equipment (1,074) 110,969 Deferred income tax expense (benefit) 3,633 (29,632) Gain on sale of property, plant and equipment (4,622) (320) Stock-based compensation 730 785 Accretion on decommissioning obligations 1,295 1,231 Accretion on convertible debentures 972 - Decommissioning expenditures (103) (1,431)Changes in non-cash working capital (note 12) 483 4,041 ----------- ----------- 37,847 29,844FINANCINGIncrease (decrease) in bank loans (872) 5,358Proceeds from issue of convertible debentures, net of issue costs (note 7) 43,860 -Proceeds from issue of share capital, net of issue costs - 29,792Proceeds from exercise of stock options 51 -Changes in non-cash working capital (note 12) (253) 103 ----------- ----------- 42,786 35,253INVESTINGProperty, plant and equipment expenditures (129,921) (87,668)Proceeds from sale of property, plant and equipment 11,570 2,399Changes in non-cash working capital (note 12) 33,694 20,171 ----------- ----------- (84,657) (65,098) ----------- -----------Decrease in cash and cash equivalents (4,024) (1)Cash and cash equivalents, beginning of period 4,024 1 ----------- -----------Cash, end of period $ - $ ----------------------------------------------------------------------------Interest received in cash $ 54 $ 67Interest paid in cash $ (3,721)$ (1,549)---------------------------------------------------------------------------See accompanying notes to the consolidated financial statements.ANDERSON ENERGY LTD.Notes to the Interim Consolidated Financial StatementsTHREE AND NINE MONTHS ENDED SEPTEMBER 30, 2011 AND 2010(Tabular amounts in thousands of dollars, unless otherwise stated)(Unaudited)1. REPORTING ENTITYAnderson Energy Ltd. ("Anderson" or the "Company") was incorporated under the laws of the province of Alberta on January 30, 2002. Anderson is engaged in the acquisition, exploration and development of oil and gas properties in western Canada.2. BASIS OF PREPARATION(a) Statement of compliance. The interim consolidated financial statements have been prepared using accounting policies consistent with International Financial Reporting Standards ("IFRS") and in accordance with International Accounting Standard 34 Interim Financial Reporting.The preparation of financial statements requires management to make judgements, estimates and assumptions that affect the application of policies and reported amounts of assets and liabilities, and revenue and expenses. The estimates and associated assumptions are based on historical experience and various other factors that are believed to be reasonable under the circumstances, the results of which form the basis of making the judgements about carrying values of asset and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.The 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 periods affected.Judgements made by management in the application of IFRS that have a significant effect on the financial statements and estimates with a significant risk of material adjustment in the current and following fiscal years are discussed in note 2(d) of the Company's interim consolidated financial statements for the three months ended March 31, 2011.These interim consolidated financial statements do not include all of the information required for full annual financial statements. These interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the interim consolidated financial statements for the three months ended March 31, 2011. These interim consolidated financial statements should be read in conjunction with the interim consolidated financial statements and notes thereto for the three months ended March 31, 2011.The interim consolidated financial statements were authorized for issuance by the Board of Directors on November 14, 2011.3. SIGNIFICANT ACCOUNTING POLICIESSignificant accounting policies are presented in notes 3 and 4 and the impact of the new standards, including reconciliations presenting the change from previous Canadian Generally Accepted Accounting Principles ("GAAP") to IFRS at January 1, 2010 and December 31, 2010 are presented in note 17 of the Company's interim consolidated financial statements for the three months ended March 31, 2011.The impacts of the new standards, including reconciliations presenting the change from previous GAAP to IFRS as at September 30, 2010 and for the three and nine months ended September 30, 2010, are presented in note 16 herein.4. PROPERTY, PLANT AND EQUIPMENTCost or deemed cost Oil and natural gas assets Other equipment TotalBalance at January 1, 2010 $ 469,762 $ 1,713 $ 471,475Additions 118,140 66 118,206Disposals (2,407) - (2,407) -------------------------------------------------------Balance at December 31, 2010 585,495 1,779 587,274Additions 139,489 71 139,560Disposals (14,802) - (14,802) -------------------------------------------------------Balance at September 30, 2011 $ 710,182 $ 1,850 $ 712,032----------------------------------------------------------------------------Accumulated depletion, depreciation and impairment losses Oil and natural gas assets Other equipment TotalOpening balance at January 1, 2010 $ - $ 1,075 $ 1,075Impairment loss at January 1, 2010 67,193 - 67,193 -------------------------------------------------------Balance at January 1, 2010 67,193 1,075 68,268Depletion and depreciation for the year 45,484 168 45,652Impairment loss 153,165 - 153,165Disposals (484) - (484) -------------------------------------------------------Balance at December 31, 2010 $ 265,358 $ 1,243 $ 266,601Depletion and depreciation for the period 37,872 104 37,976Impairment reversal, net of impairment loss (1,074) - (1,074)Disposals (5,969) - (5,969) -------------------------------------------------------Balance at September 30, 2011 $ 296,187 $ 1,347 $ 297,534----------------------------------------------------------------------------Carrying amounts Oil and natural gas assets Other equipment TotalAt December 31, 2010 $ 320,137 $ 536 $ 320,673At September 30, 2011 $ 413,995 $ 503 $ 414,498----------------------------------------------------------------------------Depletion, depreciation and impairment charges. Depletion and depreciation, impairment of property, plant and equipment, and any reversal thereof, are recognized as separate line items in the consolidated statements of operations (see note 5).5. IMPAIRMENT LOSS AND IMPAIRMENT REVERSALAt September 30, 2011, there were significant changes in the future commodity price forecasts used by the Company's independent qualified reserves evaluators when compared to December 31, 2010. The Company considered the downward price adjustments on natural gas to be an indicator of impairment for the Company's Shallow Gas and Non-Core CGUs. Similarly, the Company considered the upward price adjustments on natural gas liquids to be an indicator of impairment reversal for its Deep Gas CGU as a result of this CGU having a significant amount of natural gas liquids. All of the Company's oil and gas reserves were evaluated and reported on by independent qualified reserves evaluators at October 1, 2011 ("interim reserves report"). Based on this assessment, the Company determined that $9.7 million of previous impairments were reversed from its Deep Gas CGU and its Shallow Gas and Non-Core CGUs were impaired by $3.2 million and $5.4 million respectively.As a result of declines in natural gas forward pricing at September 30, 2010, the Company tested the Deep Gas, Shallow Gas and Non-core CGUs for impairment. Based on this assessment at September 30, 2010, the carrying amount of these CGUs were determined to be $48.3 million lower than their recoverable amount and impairments were recorded.The recoverable amount of the CGUs was estimated based on the fair value less costs to sell. The estimate of fair value less costs to sell for each of the Company's CGUs was determined by reference to information provided in the interim reserves report based on proved plus probable reserves using a pre-tax discount rate of 10%.The impairment losses and reversals since January 1, 2010 recognized in each CGU were as follows: Horizonta Deep Shallow Non-Core l Oil CGU Gas CGU Gas CGU CGU Total (1)Impairment loss at January 1, 2010 $ - $ - $ 67,193 $ - $ 67,193Impairment loss for the quarter ended March 31, 2010 - 6,587 52,827 126 59,540Impairment loss for the quarter endedJune 30, 2010 - 3,112 - - 3,112Impairment loss for the quarter ended September 30, 2010 - 15,996 28,286 4,035 48,317Impairment loss for the quarter ended December 31, 2010 - 5,384 35,033 1,779 42,196 -----------------------------------------------------------Cumulative impairment loss at December 31, 2010 $ - $ 31,079 $ 183,339 $ 5,940 $ 220,358Impairment loss (reversal) for the quarter ended September 30, 2011 - (9,725) 3,207 5,444 (1,074) -----------------------------------------------------------Cumulative impairment loss at September 30, 2011 $ - $ 21,354 $ 186,546 $ 11,384 $ 219,284Carrying value, December 31, 2010 $ 63,687 $ 94,091 $ 124,836 $ 36,764 $ 319,378Carrying value, September 30, 2011 $ 177,539 $ 96,430 $ 107,238 $ 25,470 $ 406,677----------------------------------------------------------------------------(1) Carrying values exclude inventory and corporate assets of $1.3 million at December 31, 2010 and $1.4 million at September 30, 2011.At September 30, 2011, if the discount rate had been two percent higher or two percent lower, the impairment losses and reversal recognized would have been revised as follows: Horizonta Deep Shallow Non-Core l Oil CGU Gas CGU Gas CGU CGU TotalReduction of impairment or increase in impairment reversal using an 8 percent discount rate $ - $ (8,021) $ (8,789) $ (2,183) $ (18,993)Additional impairment or reduction of impairment reversal using a 12 percent discount rate $ - $ 6,807 $ 7,738 $ 1,798 $ 16,343----------------------------------------------------------------------------6. BANK LOANSAt September 30, 2011, total bank facilities were $135 million consisting of a $100 million extendible revolving term credit facility, a $10 million working capital credit facility and a $25 million supplemental credit facility, with a syndicate of Canadian banks. The extendible revolving term credit facility and the working capital credit facility have a revolving period ending on July 11, 2012. If not extended, the extendible revolving term credit facility and working capital credit facility cease to revolve and all outstanding advances thereunder become repayable one year from the term date of July 11, 2012. The supplemental facility expires on July 11, 2012, with any outstanding amounts due in full at that time.At September 30, 2011, there were no amounts drawn under the supplemental facility. The average effective interest rate on advances under the facilities in 2011 was 5.7% (September 30, 2010 - 4.9%). The Company had $133,500 in letters of credit outstanding at September 30, 2011 that reduce the amount of credit available to the Company.Advances under the facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank's prime lending rate, bankers' acceptance or LIBOR loan rates plus applicable margins. These margins vary from 1.50% to 6.00% depending on the borrowing option used and the Company's financial ratios.Loans are secured by a floating charge debenture over all assets and guarantees by material subsidiaries. Draws over $15 million under the supplemental facility are subject to the consent of the bank syndicate at the time of the drawdown.The available lending limits of the facilities are reviewed semi-annually and are based on the bank syndicate's interpretations of the Company's reserves and future commodity prices. The bank syndicate is currently reviewing the Company's credit facilities and is scheduled to be completed by the end of November 2011. The Company does not anticipate that there will be any changes to the total amounts available under the facilities, however there can be no assurance that the amount of the available facilities or the applicable margins will not be adjusted.7. CONVERTIBLE DEBENTURESOn June 8, 2011, the Company issued $46 million of convertible unsecured subordinated debentures (the "Series B Debentures") on a bought deal basis. The Series B Debentures have a face value of $1,000, bear interest at the rate of 7.25% per annum payable semi-annually in arrears on the last day of June and December of each year commencing on December 31, 2011 and mature on June 30, 2017 ("Maturity Date"). The Series B Debentures are convertible at the holder's option at a conversion price of $1.70 per common share (the "Conversion Price"), subject to adjustment in certain events. The Series B Debentures are not redeemable by the Corporation before June 30, 2014. On and after June 30, 2014 and prior to June 30, 2016, the Series B Debentures are redeemable at the Corporation's option, in whole or in part, at a price equal to their principal amount plus accrued and unpaid interest if the weighted average trading price of the common shares on the Toronto Stock Exchange for the 20 consecutive trading days preceding the date on which the notice of redemption is given is not less than 125% of the Conversion Price. On or after June 30, 2016 and prior to the Maturity Date, the Series B Debentures may be redeemed in whole or in part at the option of the Corporation on not more than 60 days and not less than 30 days prior notice at a price equal to their principal amount plus accrued and unpaid interest. The Series B Debentures are listed and posted for trading on the TSX under the symbol "AXL.DB.B".The Series B Debentures were determined to be compound instruments. As the Series B Debentures are convertible into common shares, the liability and equity components are presented separately. The initial carrying amount of the financial liability is determined by discounting the stream of future payments of interest and principal. Using the residual method, the carrying amount of the conversion feature is the difference between the principal amount and the carrying value of the financial liability. The Series B Debentures, net of the equity component and issue costs are accreted using the effective interest rate method over the term of the Series B Debentures, such that the carrying amount of the financial liability will equal the $46 million principal balance at maturity.The following table indicates the convertible debenture activities: Debt Equity Proceeds component componentBalance, January 1, 2010 $ - $ - $ -Series A Debentures issued pursuant to prospectus, 7.5% interest rate, due January 31, 2016(1) 50,000 45,553 4,447Issue costs (2,300) (2,095) (205)Deferred tax - - (1,650)Accretion expense - 2 - -------------------------------------------Balance, December 31, 2010 $ 47,700 $ 43,460 $ 2,592Series B Debentures issued pursuant to prospectus, 7.25% interest rate, due June 30, 2017(2) 46,000 41,849 4,151Issue costs (2,140) (1,947) (193)Deferred tax - - (1,531)Accretion expense - 972 - -------------------------------------------Balance, September 30, 2011 $ 91,560 $ 84,334 $ 5,019----------------------------------------------------------------------------1. Includes 1,000 Series A Debentures issued to directors for total gross proceeds of $1.0 million.2. Includes 1,575 Series B Debentures issued to management and directors for total gross proceeds of $1.6 million.8. DECOMMISSIONING OBLIGATIONS September 30, December 31, 2011 2010Balance at January 1 $ 51,550 $ 47,657Provisions incurred 2,328 2,945Provisions settled (103) (1,549)Provisions disposed (1,247) (75)Change in estimates 6,248 918Accretion expense 1,295 1,654 -----------------------------------Ending balance $ 60,071 $ 51,550---------------------------------------------------------------------------The Company's decommissioning obligations result from its ownership interest in oil and natural gas assets including well sites and gathering systems. The total decommissioning obligation is estimated based on the Company's net ownership interest in all wells and facilities, estimated costs to reclaim and abandon these wells and facilities and the estimated timing of the costs to be incurred in future years. The Company has estimated the net present value of the decommissioning obligations to be $60.1 million as at September 30, 2011 (December 31, 2010 - $51.6 million) based on an undiscounted inflation-adjusted total future liability of $76.3 million (December 31, 2010 - $72.9 million). These payments are expected to be made over the next 25 years with the majority of costs to be incurred between 2012 and 2030. At September 30, 2011 the liability has been calculated using an inflation rate of 2.0% (December 31, 2010 - 2.0%) and discounted using a risk-free rate of 0.9% to 3.1% (December 31, 2010 - 0.8% to 4.4%) depending on the estimated timing of the future obligation.9. SHARE CAPITALAuthorized share capital. The Company is authorized to issue an unlimited number of common and preferred shares. The preferred shares may be issued in one or more series.Issued share capital. Number of Common Shares AmountBalance at January 1, 2010 150,500,401 $ 396,524Issued pursuant to prospectus(1) 21,900,000 31,755Share issue costs - (1,963)Tax effect of share issue costs - 507Stock options exercised 84,900 67Transferred from contributed surplus on stock option exercise - 35 ----------------------------------Balance at December 31, 2010 172,485,301 $ 426,925Elimination of deficit - (255,543)Stock options exercised 64,400 51Transferred from contributed surplus on stock option exercise - 27 ----------------------------------Balance at September 30, 2011 172,549,701 $ 171,460---------------------------------------------------------------------------1. Includes 352,466 common shares issued to directors for total gross proceeds of $0.5 million.Elimination of deficit. On May 16, 2011, the Company's shareholders approved the elimination of the Company's consolidated deficit as at January 1, 2011, the effective date of the Company's transition to IFRS, without reduction to the Company's stated capital or paid up capital.Stock options. The Company has an employee stock option plan under which employees, directors and consultants are eligible to purchase common shares of the Company. Options are granted using an exercise price of stock options equal to the weighted average trading price of the Company's common shares for the five trading days prior to the date of the grant. Options have terms of either five or ten years and vest equally over a three year period starting on the first anniversary date of the grant. Changes in the number of options outstanding during the nine months ended September 30, 2011 and the year ended December 31, 2010 are as follows: September 30, 2011 December 31, 2010 Weighted Weighted average average Number of exercise Number of exercise options price options priceOutstanding at January 1 12,006,232 $ 2.32 10,258,756 $ 3.22Granted during the period 4,312,300 0.75 3,950,250 1.06Exercised during the period (64,400) 0.79 (84,900) 0.79Expirations during the period (1,456,800) 4.41 (1,430,124) 5.78Forfeitures during the period (508,300) 1.07 (687,750) 1.44 --------------------------------------------------------Ending balance 14,289,032 $ 1.69 12,006,232 $ 2.32----------------------------------------------------------------------------Exercisable, end of period 6,851,932 $ 2.59 6,111,399 $ 3.53----------------------------------------------------------------------------The range of exercise prices of the outstanding options is as follows: Weighted Weighted average Number of average remaining lifeRange of exercise prices options exercise price (years)$0.67 to $0.99 6,390,500 $ 0.74 4.1$1.00 to $1.50 3,875,150 1.08 3.9$2.26 to $3.35 643,950 2.68 2.0$3.36 to $4.90 3,379,432 4.00 0.8 -------------------------------------------------Total at September 30, 2011 14,289,032 $ 1.69 3.2----------------------------------------------------------------------------The weighted average common share price at the date of exercise for stock options exercised in 2011 was $1.20 (December 31, 2010 - $1.02).The fair value of the options was estimated using the Black-Scholes model with the following weighted average inputs: September 30, September 30, 2011 2010Fair value at grant date $ 0.39 $ 0.55Common share price $ 0.75 $ 1.06Exercise price $ 0.75 $ 1.06Volatility 59% 58%Option life 5 years 5 yearsDividends 0% 0%Risk-free interest rate 1.67% 2.26%Forfeiture rate 15% 15%----------------------------------------------------------------------------This estimated forfeiture rate is adjusted to the actual forfeiture rate when each tranche vests. Stock-based compensation cost of $0.7 million (September 30, 2010 - $0.8 million) was expensed during the nine months ended September 30 2011. Stock-based compensation cost of $0.2 million (September 30, 2010 - $0.4 million) was expensed during the three months ended September 30 2011. In addition, stock-based compensation expense of $0.5 million (September 30, 2010 - $0.4 million) was capitalized during the nine months ended September 30, 2011. For the three months ended September 30, 2011, $0.2 million of stock-based compensation was capitalized (September 30, 2010 - $0.1 million).10. EARNINGS (LOSS) PER SHAREBasic and diluted earnings (loss) per share were calculated as follows: Three months ended Nine months ended September 30 September 30 2011 2010 2011 2010Earnings (loss) for the period $ 7,472 $ (39,029) $ 9,723 $ (88,242)---------------------------------------------------------------------------- Weighted average number of common shares (basic) (in thousands of shares) Common shares outstanding at beginning of period 172,550 172,400 172,485 150,500 Effect of stock options exercised - - 49 - Effect of other common shares issued - - - 19,069 --------------------------------------------------- Weighted average number of common shares (basic) 172,550 172,400 172,534 169,569 Effect of dilutive stock options - - 506 - --------------------------------------------------- Weighted average number of common shares (diluted) $ 172,550 $ 172,400 $ 173,040 $ 169,569---------------------------------------------------------------------------- Basic and diluted earnings (loss) per common share $ 0.04 $ (0.23) $ 0.06 $ (0.52)----------------------------------------------------------------------------The average market value of the Company's common shares for purposes of calculating the dilutive effect of stock options was based on quoted market prices for the period that the options were outstanding. For the three months ended September 30, 2011, 14,289,032 options (September 30, 2010 - 13,174,356 options) and 59,316,889 common share reserved for convertible debentures (September 30, 2010 - Nil) were excluded from calculating dilutive earnings as they were anti-dilutive. For the nine months ended September 30, 2011, 11,702,932 options (September 30, 2010 - 13,174,356 options) and 59,316,889 common share reserved for convertible debentures (September 30, 2010 - Nil) were excluded from calculating dilutive earnings as they were anti-dilutive.11. FINANCE INCOME AND EXPENSES Three months ended Nine months ended September 30 September 30 2011 2010 2011 2010Income: Interest income on cash equivalents $ - $ - $ 5 $ - Other 21 8 49 72Expenses: Interest and financing costs on bank loans (667) (829) (2,376) (2,223) Interest on convertible debentures (1,771) - (3,859) - Accretion on convertible debentures (462) - (972) - Accretion on decommissioni ng obligations (439) (417) (1,295) (1,231) Other (3) (7) (18) (31) --------------------------------------------------------Net finance expenses $ (3,321) $ (1,245) $ (8,466) $ (3,413)----------------------------------------------------------------------------12. SUPPLEMENTAL CASH FLOW INFORMATIONChanges in non-cash working capital is comprised of: September 30, September 30, 2011 2010Source (use) of cash Accounts receivable and accruals $ 4,863 $ 2,861 Prepaid expenses and deposits 363 263 Accounts payable and accruals 28,698 21,191 ------------------------------------ $ 33,924 $ 24,315----------------------------------------------------------------------------Related to operating activities $ 483 $ 4,041Related to financing activities $ (253) $ 103Related to investing activities $ 33,694 $ 20,171----------------------------------------------------------------------------13. FINANCIAL RISK MANAGEMENT(a) Overview. The Company's activities expose it to a variety of financial risks that arise as a result of its exploration, development, production, and financing activities such as:-- credit risk;-- liquidity risk; and-- market risk.This note presents information about the Company's exposure to each of the above risks, the Company's objectives, policies and processes for measuring and managing risk, and the Company's management of capital. Further quantitative disclosures are included throughout these consolidated financial statements.The Board of Directors oversees management's establishment and execution of the Company's risk management framework. Management has implemented and monitors compliance with risk management policies. The Company's risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company's activities.(b) Credit risk. Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from the Company's receivables from joint venture partners and oil and natural gas marketers. The maximum exposure to credit risk at year-end is as follows: September 30, December 31, 2011 2010Cash and cash equivalents $ - $ 4,024Accounts receivable and accruals 16,135 20,998 ----------------------------------- $ 16,135 $ 25,022----------------------------------------------------------------------------Accounts receivable and accruals. All of the Company's operations are conducted in Canada. The Company's exposure to credit risk is influenced mainly by the individual characteristics of each purchaser or joint venture partner.A substantial portion of the Company's accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. Receivables from oil and natural gas purchasers are normally collected on the 25th day of the month following the related sale of oil and gas production. The Company's policy to mitigate credit risk associated with these balances is to establish commercial relationships with large purchasers. The Company historically has not experienced any collection issues with its oil and natural gas purchases. Receivables from joint venture partners are typically collected within ninety days.The Company attempts to mitigate the risk from joint venture receivables by obtaining venturer pre-approval of significant capital expenditures. However, the receivables are from participants in the oil and natural gas sector, and collection of the outstanding balances is dependent on industry factors such as commodity price fluctuations, escalating costs and the risk of unsuccessful drilling. In addition, further risk exists with joint venturers as disagreements occasionally arise that increase the potential for non-collection.The Company does not typically obtain collateral from oil and natural gas purchasers or joint venturers; however, the Company does have the ability to withhold production from joint venturers in the event of non-payment.The Company's allowance for doubtful accounts as at September 30, 2011 was $0.9 million (December 31, 2010 - $1.0 million). This allowance was mostly created in prior years and is associated with prior corporate acquisitions and potential joint venture billing disputes. The Company wrote-off $0.1 million in receivables during the nine months ended September 30, 2011 (September 30, 2010 - $Nil). The Company would only choose to write-off a receivable balance (as opposed to providing an allowance) after all reasonable avenues of collection had been exhausted.The maximum exposure to credit risk for accounts receivable and accruals, net of allowance for doubtful accounts at the reporting date by type of customer was: Carrying amount September 30, December 31, 2011 2010Oil and natural gas marketing companies $ 9,941 $ 9,286Joint venture partners 4,654 7,989Other 1,540 3,723 ----------------------------------- $ 16,135 $ 20,998----------------------------------------------------------------------------As at September 30, 2011 and December 31, 2010, the Company's accounts receivable and accruals was aged as follows: September 30, December 31,Aging 2011 2010Not past due $ 14,896 $ 18,960Past due by less than 120 days 1,083 1,706Past due by more than 120 days 156 332 -----------------------------------Total $ 16,135 $ 20,998----------------------------------------------------------------------These amounts exclude offsetting amounts owing to joint venture partners that are included in accounts payable and accruals.(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 objective 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.To achieve this objective, the Company prepares annual capital expenditure budgets, which are regularly monitored and updated as considered necessary. The Company uses authorizations for expenditures on both operated and non operated projects to further manage capital expenditures. To provide capital when needed, the Company has revolving reserves-based credit facilities which are reviewed semi-annually by its lenders. These facilities are described in note 6. The Company also attempts to match its payment cycle with collection of oil and natural gas revenue on the 25th of each month.The following are the contractual maturities of financial liabilities, including associated interest payments on convertible debentures and excluding the impact of netting agreements at September 30, 2011: Less Three than One to Two to to Four to Five toFinancial one two three four five six Liabilities year years years years years yearsNon-derivative financial liabilities Accounts payable and accruals (1) $ 75,560 $ - $ - $ - $ - $ - Bank loans - principal (2) - 51,847 - - - - Convertible debentures - Interest (1) 5,626 7,085 7,085 7,085 5,210 3,335 - Principal - - - - 50,000 46,000 ---------------------------------------------------------Total $ 81,186 $ 58,932 $ 7,085 $ 7,085 $ 55,210 $ 49,335----------------------------------------------------------------------------1. Accounts payable and accruals includes $1.7 million of interest relating to convertible debentures. The total cash interest payable in less than one year on the convertible debentures is $7.3 million.2. Assumes the credit facilities are not renewed on July 11, 2012.(d) Market risk. Market risk is the risk that changes in market prices, such as commodity prices, foreign exchange rates and interest rates will affect the Company's income or the value of the financial instruments. The objective of market risk management is to manage and control market risk exposures within acceptable parameters, while optimizing the return.The Company may use both financial derivatives and physical delivery sales contracts to manage market risks. All such transactions are conducted within risk management tolerances that are reviewed by the Board of Directors.Currency risk. Prices for oil are determined in global markets and generally denominated in United States dollars. Natural gas prices obtained by the Company are influenced by both U.S. and Canadian demand and the corresponding North American supply, and recently, by imports of liquefied natural gas. The exchange rate effect cannot be quantified but generally an increase in the value of the Canadian dollar as compared to the U.S. dollar will reduce the prices received by the Company for its petroleum and natural gas sales.There were no financial instruments denominated in U.S. dollars at September 30, 2011 or December 31, 2010.Interest rate risk. Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The interest charged on the outstanding bank loans fluctuates with the interest rates posted by the lenders. The Company has not entered into any mitigating interest rate hedges or swaps, however the Company has $50 million and $46 million of convertible debentures with fixed interest rates of 7.5% and 7.25% respectively, maturing January 31, 2016 and June 30, 2017 (see note 7). Had the borrowing rate on bank loans been 100 basis points higher (or lower) throughout the nine months ended September 30, 2011, earnings would have been affected by $0.3 million (September 30, 2010 - $0.2 million) based on the average bank debt balance outstanding during the period.Commodity price risk. Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for oil and natural gas are impacted by both the relationship between the Canadian and U.S. dollar and world economic events that dictate the levels of supply and demand.It is the Company's policy to economically hedge some oil and natural gas sales through the use of various financial derivative forward sales contracts and physical sales contracts. The Company does not apply hedge accounting for these contracts. The Company's production is usually sold using "spot" or near term contracts, with prices fixed at the time of transfer of custody or on the basis of a monthly average market price. The Company, however, may give consideration in certain circumstances to the appropriateness of entering into long term, fixed price sales contracts. The Company does not enter into commodity contracts other than to meet the Company's expected sale requirements.At September 30, 2011 the following derivative contracts were outstanding and recorded at estimated fair value: Weighted Average Fixed Price (NYMEXType of Contract(1) Commodity Volume Canadian $) Remaining Period 1,250 Oct 1, 2011 toFinancial swap Crude oil bbls/day $ 91.96/bbl Dec 31, 2011 250 Oct 1, 2011 toFinancial swap Crude oil bbls/day $ 105.30/bbl Dec 31, 2011 500 Jan 1, 2012 toFinancial swap Crude oil bbls/day $ 106.04/bbl Mar 31, 2012 1,000 Jan 1, 2012 toFinancial swap Crude oil bbls/day $ 103.93/bbl Dec 31, 2012----------------------------------------------------------------------------1. Swap indicates fixed price payable to Anderson in exchange for floating price payable to counterparty.The estimated fair value of the financial oil contracts has been determined on the amounts the Company would receive or pay to terminate the oil contracts. At September 30, 2011, the Company estimates that it would have received $9.2 million to terminate these contracts.The fair value of the financial commodity risk management contracts have been allocated to current and non-current liabilities on a contract by contract basis as follows: September 30, December 31, 2011 2010Assets: Current $ 7,551 $ - Long-term 1,697 -Current liability - (1,918) -----------------------------------Net asset (liability) position $ 9,248 $ (1,918)----------------------------------------------------------------------------The fair value of derivative contracts at September 30, 2011 would have been impacted as follows had the oil prices used to estimate the fair value changed by: Effect of an Effect of a increase in decrease in price on after- price on after- tax earnings tax earningsCanadian $1.00 per barrel change in the oil prices $ (410) $ 410----------------------------------------------------------------------------In June 2011, the Company entered into physical sales contracts to sell 15,000 GJ per day of natural gas between July 1, 2011 and October 31, 2011 at a weighted average AECO price of $4.06 per GJ. The gains realized to September 30, 2011 were $0.8 million and have been included in oil and gas sales.(e) Capital management. Anderson's capital management policy is to maintain a strong, but flexible capital structure that optimizes the cost of capital and maintains investor, creditor and market confidence while sustaining the future development of the business.The Company manages its capital structure and makes adjustments to it in the light of changes in economic conditions and the risk characteristics of the underlying petroleum and natural gas assets. The Company's capital structure includes shareholders' equity of $195.3 million, bank loans of $51.8 million, convertible debentures with a face value of $96.0 million and the working capital deficiency of $56.7 million, excluding the current portion of unrealized gain on derivative contracts. In order to maintain or adjust the capital structure, the Company may from time to time issue shares, seek additional debt financing and adjust its capital spending to manage current and projected debt levels.Consistent with other companies in the oil and gas sector, Anderson monitors capital based on the ratio of total debt to funds from operations. This ratio is calculated by dividing total debt at the end of the period (comprised of the cash working capital deficiency, the liability component of convertible debentures and outstanding bank loans) by the annualized current quarter funds from operations (cash flow from operating activities before changes in non-cash working capital including decommissioning expenditures). This ratio may increase at certain times as a result of acquisitions, the timing of capital expenditures and market conditions. In order to facilitate the management of this ratio, the Company prepares annual capital expenditure budgets, which are updated as necessary depending on varying factors including current and forecast crude oil and natural gas prices, capital deployment and general industry conditions. The annual and updated budgets are approved by the Board of Directors. September 30, December 31, 2011 2010Bank loans $ 51,847 $ 52,719Current liabilities(1) 75,560 46,862Current assets(1) (18,824) (28,074)---------------------------------------------------------------------------Net debt before convertible debentures $ 108,583 $ 71,507Convertible debentures (liability component) 84,334 43,460---------------------------------------------------------------------------Total net debt $ 192,917 $ 114,967Cash from operating activities in quarter $ 11,893 $ 10,489Decommissioning expenditures 61 118Changes in non-cash working capital 701 (1,324)---------------------------------------------------------------------------Funds from operations in quarter $ 12,655 $ 9,283Annualized current quarter funds from operations $ 50,620 $ 37,132Net debt before convertible debentures to funds from operations 2.1 1.9Total net debt to funds from operations 3.8 3.1---------------------------------------------------------------------------(1) Excludes unrealized gains (losses) on derivative contracts.There were no changes in the Company's approach to capital management during the period.As at September 30, 2011, the Company's ratio of net debt before convertible debentures to annualized funds from operations was 2.1 to 1 (December 31, 2010 - 1.9 to 1). As at September 30, 2011, the Company's ratio of total net debt to annualized funds from operations was 3.8 to 1 (December 31, 2010 - 3.1 to 1). The high ratios reflect the capital expenditures required to make the transition from a gas weighted company to an oil weighted company. The increase in the ratio from December 31, 2010 is the result higher capital spending in the nine months ended September 30, 2011, partially offset by higher funds from operations as a result of the transition to an oil weighted Company. As new crude oil production is brought on-stream at higher expected operating margins, the debt to funds from operations ratio is expected to decrease.Neither the Company nor any of its subsidiaries are subject to externally imposed capital requirements. The credit facilities are subject to a semi-annual review of the borrowing base which is directly impacted by the value of the oil and natural gas reserves.14. RELATED PARTY TRANSACTIONSOn June 8, 2011, the Company issued 1,575 Series B Convertible Debentures to management and directors at a price of $1,000 per convertible debenture for total gross proceeds of $1.6 million as part of a $46.0 million bought deal offering of convertible debentures.On December 31, 2010, the Company issued 1,000 Series A Convertible Debentures to directors at a price of $1,000 per convertible debenture for total gross proceeds of $1.0 million as part of a $50.0 million bought deal offering of convertible debentures.In February 2010, the Company issued 352,466 common shares to directors at a price of $1.45 per share for total gross proceeds of $0.5 million as part of a $27.9 million bought deal offering of common shares.15. COMMITMENTSThe Company has entered into an agreement to lease office space until November 30, 2012. Future minimum lease payments are expected to be $0.5 million in the remainder of 2011 and $1.6 million in 2012.On December 2, 2010, the Company entered into a facilities construction and operation agreement pursuant to which it is committed to ship a minimum volume of gross crude oil through new facilities and pipelines being constructed in one of its core areas. The total financial commitment is $2.6 million to be incurred over a minimum of five years. The contract contains a minimum volume requirement per year for the first five years following completion of construction which is expected to be in the third quarter of 2011. In the event that the volume shipped is less than the minimum volume, the Company will be subject to a fee per cubic metre of oil on the difference between actual volumes shipped and the minimum volume required. Conversely, if the Company exceeds the minimum volume requirement in a single year, the excess is carried forward as a credit to the minimum volume requirement in the subsequent year. If no volumes were shipped, the minimum of $0.26 million would be payable each year. After the total contracted volumes have been shipped, the contract will automatically renew for one year periods unless terminated.The Company entered into firm service transportation agreements for approximately 23 million cubic feet per day of gas sales in central Alberta for various terms expiring in one to nine years. Based on rate schedules announced to date, the payments in each of the next five years and thereafter are estimated as follows: Committed Committed volume (MMcfd) amountRemainder of 2011 23 $ 4162012 19 $ 1,3322013 8 $ 8592014 4 $ 6792015 4 $ 604Thereafter 12 $ 433----------------------------------------------------------------------------On January 29, 2009, the Company executed a farm-in agreement with a large international oil and gas company (the "Farmor") on lands near its existing core operations. Under the farm-in agreement, the Company has access to 388 gross (205 net) sections of land. During the commitment phase of the transaction, the Company is committed to drill, complete and equip 200 wells to earn an interest in up to 120 sections. The Company was originally obligated to complete the drilling of the wells on or before March 31, 2012. Subsequent to September 30, 2011, the terms of the farm-in agreement were modified to extend the commitment date to March 31, 2013. The Company's equipping obligation is up to, but does not include, multi-well gathering systems downstream of field compression and/or gas plants. The Company has an option to continue the farm-in transaction until March 1, 2014 by committing to drill a minimum of 100 additional wells under similar terms as in the commitment phase to earn a minimum of 50 sections of land. Following the commitment and/or option phases, the parties to the agreement can then jointly develop the lands on denser drilling spacing under terms of an operating agreement.The Company commenced drilling in the fourth quarter of 2009 and currently estimates that the average working interest of the 200 well capital commitment will be approximately 80% to 85%, based on partner participation identified to date. As of December 31, 2010, the Company has drilled 126 wells under the farm-in agreement and plans to defer the drilling of the remaining 74 wells until 2012. The Company earns its interest in each well as the well is put on production. A $550,000 penalty is payable for each well not drilled under the commitment as of March 31, 2013, subject to certain reductions due to unavoidable events beyond the Company's control and rights of first refusal. The Company estimates that its minimum commitment to drill the remaining 74 wells is $10 million.16. RECONCILIATION FROM CANADIAN GAAP TO IFRSThis note sets out how the transition from CGAAP to IFRS has affected the Company's statement of financial position, comprehensive loss and shareholders' equity.Statement of financial position at September 30, 2010: Effect of transition to IFRS Canadian Impairment Decommissioning(in thousands of dollars) GAAP (note 16b) (note 16d)ASSETS Current assets: Cash and cash equivalents $ - $ - $ - Accounts receivable and accruals 20,129 Prepaid expenses and deposits 3,515 -------------------------------------------- 23,644 - - Property, plant and equipment (note 16a) 501,732 (178,162) 1,637 -------------------------------------------- $ 525,376 $ (178,162) $ 1,637----------------------------------------------------------------------------LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities: Accounts payable and accruals $ 58,080 $ - $ -Bank loans 67,762 Decommissioning obligations 35,469 14,757 Deferred tax liability (asset) 23,263 (44,892) (3,279) -------------------------------------------- 184,574 (44,892) 11,478 Shareholders' Equity:Share capital $ 421,936 $ - $ -Contributed surplus 7,778Deficit (note 16i) (88,912) (133,270) (9,841) -------------------------------------------- 340,802 (133,270) (9,841) $ 525,376 $ (178,162) $ 1,637-------------------------------------------------------------------------------------------------------------------------------------------------------- Effect of transition to IFRS Share- based Depletion and Other PP&E payments depreciation adjs(in thousands of dollars) note (16e) (note 16c) (note 16c)ASSETS Current assets: Cash and cash equivalents $ - $ - $ - Accounts receivable and accruals Prepaid expenses and deposits ----------------------------------------------- - - - Property, plant and equipment (note 16a) (292) 24,043 (208) ----------------------------------------------- $ (292) $ 24,043 $ (208)----------------------------------------------------------------------------LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities: Accounts payable and accruals $ - $ - $ -Bank loans Decommissioning obligations 156 Deferred tax liability (asset) 6,050 (361) ----------------------------------------------- - 6,050 (205) Shareholders' Equity:Share capital $ - $ - $ -Contributed surplus (214)Deficit (note 16i) (78) 17,993 (3) ----------------------------------------------- (292) 17,993 (3) $ (292) $ 24,043 $ (208)-------------------------------------------------------------------------------------------------------------------------------------------------------- Effect of transition to IFRS Flow through Deferred shares (note Taxes (note(in thousands of dollars) 16f) 16h) IFRSASSETS Current assets: Cash and cash equivalents $ - $ - $ - Accounts receivable and accruals 20,129 Prepaid expenses and deposits 3,515 ----------------------------------------------- - - 23,644 Property, plant and equipment (note 16a) 348,750 ----------------------------------------------- $ - $ - $ 372,394----------------------------------------------------------------------------LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities: Accounts payable and accruals $ - $ - $ 58,080Bank loans 67,762 Decommissioning obligations 50,382 Deferred tax liability (asset) (19,219) ----------------------------------------------- - - 157,005 Shareholders' Equity:Share capital $ 5,336 $ (449) $ 426,823Contributed surplus 7,564Deficit (note 16i) (5,336) 449 (218,998) ----------------------------------------------- - - 215,389 $ - $ - $ 372,394--------------------------------------------------------------------------------------------------------------------------------------------------------16. RECONCILIATION FROM CANADIAN GAAP TO IFRS (Continued)Reconciliation of consolidated statement of operations and comprehensive loss for the three months ended September 30, 2010: Effect of transition to IFRS Impairment Decommissioning(in thousands of dollars) Canadian GAAP (note 16b) (note 16d)Oil and gas sales $ 18,928 $ - $ -Royalties (1,665) --------------------------------------------------Revenue, net of royalties 17,263 - -Loss on sale of property, plant and equipment - -------------------------------------------------- 17,263 - -Operating expenses 6,343Transportation expenses 172Depletion and depreciation 18,937Impairment of property, plant and equipment - 48,317General and administrative expenses, including stock-based compensation 2,377 --------------------------------------------------Loss from operating activiites (10,566) (48,317) -Finance income 8Finance expenses, including accretion (1,481) 228 --------------------------------------------------Net finance expenses (1,473) - 228Loss before taxes (12,039) (48,317) 228Deferred income tax benefit (2,993) (12,345) 57 --------------------------------------------------Loss and comprehensive loss for the period $ (9,046) $ (35,972) $ 171---------------------------------------------------------------------------- Effect of transition to IFRS Share- Depletion based and Other PP&E payments depreciation adjs(in thousands of dollars) (note 16e) (note 16c) (note 16c) IFRSOil and gas sales $ - $ - $ - $ 18,928Royalties (1,665) ---------------------------------------------------Revenue, net of royalties - - - 17,263Loss on sale of property, plant and equipment (388) (388) --------------------------------------------------- - - (388) 16,875Operating expenses 6,343Transportation expenses 172Depletion and depreciation (8,306) 10,631Impairment of property, plant and equipment 48,317General and administrative expenses, including stock-based compensation (102) 150 2,425 ---------------------------------------------------Loss from operating activiites 102 8,306 (538) (51,013)Finance income 8Finance expenses, including accretion (1,253) ---------------------------------------------------Net finance expenses - - - (1,245)Loss before taxes 102 8,306 (538) (52,258)Deferred income tax benefit - 2,090 (38) (13,229) ---------------------------------------------------Loss and comprehensive loss for the period $ 102 $ 6,216 $ (500) $ (39,029)----------------------------------------------------------------------------Reconciliation of consolidated statement of operations and comprehensive loss for the nine months ended September 30, 2010: Effect of transition to IFRS Impairment Decommissioning(in thousands of dollars) Canadian GAAP (note 16b) (note 16d)Oil and gas sales $ 62,511 $ - $ -Royalties (6,755) --------------------------------------------------Revenue, net of royalties 55,756 - -Gain on sale of property, plant and equipment - -------------------------------------------------- 55,756 - -Operating expenses 19,962Transportation expenses 387Depletion and depreciation 56,486Impairment of property, plant and equipment - 110,969General and administrative expenses, including stock-based compensation 6,501 --------------------------------------------------Loss from operating activiites (27,580) (110,969) -Finance income 72Finance expenses, including accretion (4,143) 658 --------------------------------------------------Net finance expenses (4,071) - 658Loss before taxes (31,651) (110,969) 658Deferred income tax benefit (7,761) (27,978) 165 --------------------------------------------------Loss and comprehensive loss for the period $ (23,890) $ (82,991) $ 493---------------------------------------------------------------------------- Effect of transition to IFRS Share- Depletion based and Other PP&E payments depreciation adjs(in thousands of dollars) (note 16e) (note 16c) (note 16c) IFRSOil and gas sales $ - $ - $ - $ 62,511Royalties (6,755) ---------------------------------------------------Revenue, net of royalties - - - 55,756Gain on sale of property, plant and equipment 320 320 --------------------------------------------------- - - 320 56,076Operating expenses 19,962Transportation expenses 387Depletion and depreciation (24,043) 32,443Impairment of property, plant and equipment 110,969General and administrative expenses, including stock-based compensation (156) 431 6,776 ---------------------------------------------------Loss from operating activiites 156 24,043 (111) (114,461)Finance income 72Finance expenses, including accretion (3,485) ---------------------------------------------------Net finance expenses - - - (3,413)Loss before taxes 156 24,043 (111) (117,874)Deferred income tax benefit - 6,050 (108) (29,632) ---------------------------------------------------Loss and comprehensive loss for the period $ 156 $ 17,993 $ (3) $ (88,242)----------------------------------------------------------------------------Notes to reconciliationsa. IFRS 1 - Deemed Cost. The Company applied the IFRS 1 exemption whereby the value of its opening plant, property and equipment at January 1, 2010 was deemed to be equal to the net book value as determined under Canadian GAAP and the corresponding CGUs were tested for impairment. The Company chose to allocate its costs to its CGUs based on proved plus probable reserves volumes.b. IAS 36 Adjustments - Impairment of Assets. Under Canadian GAAP, impairment of non-financial assets is assessed on the basis of an asset's estimated undiscounted future cash flows compared with the asset's carrying amount and if impairment is indicated, discounted cash flows are prepared to quantify the amount of the impairment. Under IFRS, impairment is assessed based on recoverable amount (greater of value in use or fair value less costs to sell) compared with the asset's carrying amount to determine the recoverable amount and measure the amount of the impairment. In addition, under IFRS, where a non-financial asset does not generate largely independent cash inflows, the Company is required to perform its test at a cash generating unit level, which is the smallest identifiable grouping of assets that generates largely independent cash inflows. Canadian GAAP impairment is based on undiscounted cash flows using asset groupings with both independent cash inflows and cash outflows.Upon transition to IFRS, this resulted in a $67.2 million reduction in property, plant and equipment. For the three months and nine months ended September 30, 2010 as well as the year ended December 31, 2010 the Company recognized impairments of $48.3 million, $111.0 million and $153.2 million respectively with a corresponding reduction in property, plant and equipment as a result of declines in the forward natural gas price curves.c. IAS 16 Adjustments - Property, Plant and Equipment.Depletion and depreciation. Upon transition to IFRS, the Company adopted a policy of depleting and depreciating oil and natural gas interests on a unit of production basis over proved plus probable reserves. The depletion and depreciation policy under Canadian GAAP was based on units of production over proved reserves. In addition, depletion and depreciation was calculated on the Canadian full cost pool under Canadian GAAP. IFRS requires depletion and depreciation to be calculated based on individual components.For the three months ended September 30, 2010, the use of proved plus probable reserves as well as the lower net book value due to the impairments of the Company's Shallow Gas, Deep Gas and Non-core CGUs resulted in a decrease to depletion and depreciation of $8.3 million with a corresponding increase to property, plant and equipment. For the nine months ended September 30, 2010, depletion and depreciation decreased by $24.0 million for the same reasons.Other adjustments. IFRS requires that gains or losses be reported on the disposition of property, plant and equipment. Under Canadian GAAP, gains or losses on disposition of property, plant and equipment were only reported when the disposition resulted in more than a 20 percent change in the depletion rate. As a result of this requirement, the Company reported a loss of $0.4 million and gain of $0.3 million during the three and nine months ended September 30, 2010 respectively with an increase in property, plant and equipment where the proceeds were originally recorded under Canadian GAAP and a net increase to decommissioning obligations that were assumed as part of an asset exchange of $0.2 million.IFRS also requires that the capitalization of general and administrative costs be limited to directly attributable costs. Under Canadian GAAP, a reasonable allocation of general and administrative costs to property, plant and equipment was acceptable. As a result of the change in the capitalization criteria, the Company increased its general and administrative expense by $0.2 million during the three months ended September 30, 2010 and $0.4 million during the nine months ended September 30, 2010 with a corresponding decrease in property, plant and equipment.Under Canadian GAAP, a deferred tax adjustment was recorded related to stock-based compensation costs capitalized. No such adjustment is made under IFRS. As a result of this change, property, plant and equipment was reduced by $0.3 million at September 30, 2010 with a corresponding decrease to the deferred tax liability.d. IAS 37 Adjustments - Provisions, Contingent Liabilities and Contingent Assets. Consistent with IFRS, decommissioning obligations (asset retirement obligations under Canadian GAAP) were measured under Canadian GAAP based on the estimated cost of decommissioning, discounted to their net present value upon initial recognition. Under Canadian GAAP, asset retirement obligations were discounted at a credit adjusted risk fee rate of eight to 10 percent. 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 of one to four percent. Decommissioning obligations are also required to be re-measured based on changes in estimates including discount rates.The IFRS 1 exemption was utilized for asset retirement obligations associated with oil and gas properties and the Company re-measured asset retirement obligations as at January 1, 2010 under IAS 37 with a corresponding adjustment to opening retained earnings. Upon transition to IFRS this resulted in a $13.8 million increase in the decommissioning obligations with a corresponding decrease in retained earnings.At September 30, 2010, using risk-free rates of one to four percent, depending on the estimated timing of the future obligation, the Company increased its decommissioning obligations by $14.8 million from Canadian GAAP. The Company also increased the value of its plant, property and equipment for September 30, 2010 by $1.6 million.As a result of the change in the decommissioning obligation, accretion expense decreased by $0.2 million during the three months ended September 30, 2010 under IFRS compared to Canadian GAAP. For the nine months ended September 30, 2010, accretion expense decreased by $0.7 million. In addition, under Canadian GAAP accretion of the discount was included in depletion and depreciation. Under IFRS, it is included in finance expenses.e. IFRS 2 Adjustments - Share-based Payments. Under Canadian GAAP, the Company recognized an expense related to stock-based compensation on a straight-line basis through the date of full vesting and incorporated a forfeiture multiple, which was optional under Canadian GAAP. Under IFRS, the Company is required to recognize the expense over the individual vesting periods for the graded vesting awards and estimate a forfeiture rate. For the three months ended September 30, 2010, the Company reduced the amount of stock-based compensation expense by $0.1 million and reduced the amount capitalized by $0.2 million. For the nine months ended September 30, 2010, the Company reduced the amount of stock-based compensation expense by $0.2 million and reduced the amount capitalized by $0.4 million. In addition, under Canadian GAAP, stock-based compensation was disclosed separately on the consolidated statement of operations and comprehensive loss. Under IFRS, stock-based compensation is included in general and administrative expenses.f. Flow Through Shares. Under Canadian GAAP, the Company recorded the deferred tax impact on renouncement of flow through shares against share capital. Under IFRS, the Company is required to record a premium liability when the flow through shares are issued, which is relieved upon renouncement, with the difference going to deferred tax expense. As a result of this change in the treatment of deferred taxes, at transition, the Company recorded an additional $5.3 million to share capital with a corresponding reduction in retained earnings for flow through shares that had been previously issued and fully renounced at transition.g. Convertible Debentures. Under Canadian GAAP, the Company did not record a deferred tax difference on its convertible debentures. Under IFRS, the Company is required to record the deferred tax difference between the fair value of the liability component of the convertible debentures and the tax value of the convertible debentures with the difference being booked against the equity component of convertible debentures. This change did not have an impact on the September 30, 2010 statement of financial position as the convertible debentures were not issued until December 31, 2010.h. IAS 12 Adjustments - Income Taxes. The aforementioned changes increased (decreased) the net deferred tax liability as follows based on a tax rate of 25 percent: September 30, 2010Impairment of plant, property and equipment (note 16b) $ (44,892)Depletion and depreciation (note 16c) 6,050Decommissioning obligation (note 16d) (3,279)Other adjustments (note 16c) (361) ----------------Decrease in deferred tax liabilities $ (42,482)----------------------------------------------------------------------------IFRS requires that adjustments to the future tax rates used to calculate deferred taxes be traced and recorded against the original source of the timing difference as opposed to through earnings as was done under Canadian GAAP. As a result of this change at January 1, 2010, the Company reclassified $0.5 million in deferred taxes previously recorded in income against share issue costs.The effect on the consolidated statements of operations and comprehensive loss for the three and nine months ended September 30, 2010 was to decrease the previously reported tax charge for the period by $10.2 million and $21.9 million respectively.i. Retained Earnings Adjustments. The aforementioned changes increased (decreased) increased retained earnings as follows on an after-tax basis: September 30, 2010Impairment of plant, property and equipment (note 16b) $ (133,270)Decommissioning obligations (note 16d) (9,841)Flow through shares (note 16f) (5,336)Depletion and depreciation (note 16c) 17,993Gain on sale of plant, property and equipment (note 16c) 320Deferred taxes on share issue costs (note 16h) 449General and administrative expenses (note 16c) (323)Stock-based compensation (note 16e) (78) ----------------Decrease in retained earnings $ (130,086)----------------------------------------------------------------------------j. Adjustments to the Company's Cash Flow Statements under IFRS. The reconciling items discussed above between Canadian GAAP and IFRS policies have no material impact on the cash flows generated by the Company. As a result of the change in capitalized general and administrative expenses, there was a reduction of $0.4 million to operating cash flows, with and equal and opposite effect on investing cash flows for the nine months ended September 30, 2010 and $0.2 million for the three months ended September 30, 2010.DirectorsJ.C. AndersonCalgary, AlbertaBrian H. DauCalgary, AlbertaChristopher L. Fong (1)(2)(3)Calgary, AlbertaGlenn D. Hockley (1)(3)Calgary, AlbertaDavid J. Sandmeyer (2)(3)Calgary, AlbertaDavid G. Scobie (1)(2)Calgary, AlbertaMember of:(1) Audit Committee(2) Compensation & CorporateGovernance Committee(3) Reserves CommitteeAuditorsKPMG LLPIndependent EngineersGLJ Petroleum ConsultantsLegal CounselBennett Jones LLPRegistrar & Transfer AgentValiant Trust CompanyStock ExchangeThe Toronto Stock ExchangeSymbol AXL, AXL.DB, AXL.DB.BOfficersJ.C. AndersonChairman of the BoardBrian H. DauPresident & Chief Executive OfficerDavid M. SpykerChief Operating OfficerM. Darlene WongVice President Finance, Chief FinancialOfficer & SecretaryBlaine M. ChicoineVice President, Drilling and CompletionsSandra M. DrinnanVice President, LandPhilip A. HarveyVice President, ExploitationJamie A. MarshallVice President, ExplorationPatrick M. O'RourkeVice President, ProductionAbbreviations usedAECO - intra-Alberta Nova inventory transfer pricebbl - barrelbpd - barrels per dayMstb - thousand stock tank barrelsMbbls - thousand barrelsBOE - barrels of oil equivalentBOED - barrels of oil equivalent per dayBOPD - barrels of oil per dayMBOE - thousand barrels of oil equivalentMMBOE - million barrels of oil equivalentGJ - gigajouleMcf - thousand cubic feetMcfd - thousand cubic feet per dayMMcf - million cubic feetMMcfd - million cubic feet per dayNGL - natural gas liquidsWTI - West Texas IntermediateFOR FURTHER INFORMATION PLEASE CONTACT: Brian H. DauAnderson Energy Ltd.President & Chief Executive Officer(403) 262-6307info@andersonenergy.caOR700 Selkirk House, 555 4th Avenue S.W.Anderson Energy Ltd.Calgary, Alberta, Canada T2P 3E7(403) 262-6307(403) 261-2792 (FAX)www.andersonenergy.ca