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Press release from Marketwire

Anderson Energy Announces 2012 Third Quarter Results

Tuesday, November 13, 2012

Anderson Energy Announces 2012 Third Quarter Results09:26 EST Tuesday, November 13, 2012CALGARY, ALBERTA--(Marketwire - Nov. 13, 2012) - 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, 2012. HIGHLIGHTSFunds from operations in the third quarter of 2012 were $5.7 million. Funds from operations for the first nine months of 2012 were $23.9 million. Production in the third quarter of 2012 was 5,770 bpd, of which oil and NGL production averaged 1,850 bpd. Oil represented 1,274 bpd of total production. Oil and NGL revenue represented 72% of Anderson's total oil and gas sales in the third quarter of 2012 compared to 63% in the same period of 2011. The operating netback per BOE in the third quarter of 2012 was $20.54 per BOE compared to $26.10 per BOE in the third quarter of 2011. The operating netback was primarily impacted by declining commodity prices, partially offset by a reduction in operating costs resulting from the Company's prior investments in low operating cost crude oil infrastructure which has significantly lowered transportation costs. Cardium oil netbacks averaged approximately $43.29 per BOE in the third quarter of 2012. GLJ Petroleum Consultants ("GLJ") have completed an interim reserves report of all of the Company's oil and natural gas properties effective October 1, 2012 including properties sold by the Company in the fourth quarter of 2012. Proved plus probable ("P&P") BOE reserves are 25.3 MMBOE. Subsequent to September 30, 2012, the Company has sold or agreed to sell approximately 1,560 BOED of production (75% natural gas) for cash consideration of $37.5 million subject to normal closing adjustments. Approximately one-half of these dispositions have now closed and the remainder is scheduled to close before the end of November 2012. As previously announced, the Company's board of directors (the "Board of Directors") is conducting a process to identify, examine and consider a range of strategic alternatives with a view to enhancing shareholder value. Anderson has engaged BMO Capital Markets and RBC Capital Markets as financial advisors to assist in this process. Since January 1, 2012, the Company has sold or has agreed to sell approximately $74 million of oil and gas properties subject to normal closing adjustments. FINANCIAL AND OPERATING HIGHLIGHTSThree months ended September 30Nine months ended September 30(thousands of dollars, unless otherwise stated)20122011% Change20122011% ChangeOil and gas sales*$17,013$28,513(40%)$62,532$85,665(27%)Revenue, net of royalties*$15,284$24,970(39%)$56,019$76,029(26%)Funds from operations$5,725$12,655(55%)$23,947$37,467(36%)Funds from operations per shareBasic and diluted$0.03$0.07(57%)$0.14$0.22(36%)Earnings (loss) before effect of impairments$94$6,667(99%)$(7,598)$8,918(185%)Earnings (loss) per share before effect of impairments, basic and diluted$-$0.04(100%)$(0.04)$0.05(180%)Earnings (loss)$94$7,472(99%)$(22,598)$9,723(332%)Earnings (loss) per shareBasic and diluted$-$0.04(100%)$(0.13)$0.06(317%)Capital expenditures, net of (proceeds) on dispositions$(28,986)$49,713(158%)$(12,110)$118,351(110%)Bank loans plus cash working capital deficiency$96,991$108,583(11%)Convertible debentures$86,247$84,3342%Shareholders' equity$141,751$195,251(27%)Average shares outstanding (thousands)Basic172,550172,550-172,550172,534-Diluted172,550172,550-172,550173,040-Ending shares outstanding (thousands)172,550172,550-Average daily sales:Natural gas (Mcfd)23,51930,038(22%)25,79931,972(19%)Oil (bpd)1,2741,709(25%)1,6321,6151%NGL (bpd)576636(9%)6766671%Barrels of oil equivalent (BOED)5,7707,351(22%)6,6077,610(13%)Average prices:Natural gas ($/Mcf)$2.24$3.85(42%)$1.98$3.74(47%)Oil ($/bbl)$80.44$89.05(10%)$84.03$91.59(8%)NGL ($/bbl)$51.59$66.07(22%)$58.06$68.76(16%)Barrels of oil equivalent ($/BOE)*$32.05$42.16(24%)$34.54$41.23(16%)Realized gain (loss) on derivative contracts ($/BOE)$3.16$1.29145%$1.77$(0.17)1141%Royalties ($/BOE)$3.26$5.24(38%)$3.60$4.64(22%)Operating costs ($/BOE)$11.28$11.221%$10.62$11.30(6%)Transportation costs ($/BOE)$0.13$0.89(85%)$0.25$0.63(60%)Operating netback ($/BOE)$20.54$26.10(21%)$21.84$24.49(11%)Wells drilled (gross)-21(100%)341(93%)* Includes royalty and other income classified with oil and gas sales, but excludes realized and unrealized gains and losses on derivative contracts.FINANCIAL RESULTS Capital expenditures before dispositions were $1.7 million in the third quarter of 2012, and proceeds on disposition were $30.7 million in the third quarter of 2012. This compares to capital expenditures of $55.9 million before dispositions and proceeds on dispositions of $6.2 million in the third quarter of 2011. Anderson's funds from operations were $5.7 million in the third quarter of 2012 compared to $12.7 million in the third quarter of 2011. Oil and gas sales were lower in the third quarter of 2012 as compared to the third quarter of 2011 due to a 42% decrease in gas prices, a 22% decrease in NGL prices, a 10% decrease in oil prices, and a 22% decrease in production related to property dispositions, natural declines in oil and gas production and lower capital spending. During the third quarter of 2012, oil and NGL sales represented 72% of Anderson's total oil and gas sales compared to 63% in the third quarter of 2011. The Company has 500 bpd of fixed price oil swaps for October 2012 and 1,000 bpd of fixed price oil swaps for November and December 2012. The Company's operating netback was $20.54 per BOE in the third quarter of 2012 compared to $26.10 per BOE in the third quarter of 2011. Anderson's netback for its Cardium horizontal properties in the third quarter of 2012 was approximately $43.29 per BOE (exclusive of hedging). Average wellhead natural gas price ($/Mcf)Average oil and NGL price ($/bbl)Revenue ($/BOE)Operating netback ($/BOE)Funds from operations ($/BOE)20103.9663.2431.3117.4413.2220113.6086.5342.1325.8919.40First quarter of 20122.0182.9038.2823.6216.12Second quarter of 20121.7273.1532.7021.0412.25Third quarter of 20122.2471.4632.0520.5410.78The Company recorded earnings of $0.1 million in the third quarter of 2012 primarily due to the gain recognized on asset dispositions. Subsequent to September 30, 2012, Anderson sold or has agreed to sell oil and gas properties for cash consideration of approximately $37.5 million subject to normal closing adjustments. Approximately one-half of the dispositions closed at the end of October 2012 with the remainder to close before the end of November 2012. The Company's bank lines will step down to $70 million after the closing of the dispositions. Pro forma the dispositions, outstanding bank loans would be $51.4 million at September 30, 2012. COMMODITY PRICES The Company's average crude oil and natural gas liquids sales prices in the third quarter of 2012 were $80.44 and $51.59 per barrel respectively compared to $89.05 and $66.07 per barrel in the third quarter of 2011. Light, sweet oil differentials between Cushing, Oklahoma and Edmonton, Alberta were an average $7.21 per bbl U.S. discount in the third quarter of 2012, $10.25 per bbl U.S. discount in the second quarter of 2012, $10.53 per bbl U.S. discount in the first quarter of 2012, compared to an average $1.46 per bbl U.S. premium as recently as the fourth quarter of 2011. In the fourth quarter of 2012, light sweet, oil differentials are expected to be comparable on average to the third quarter of 2012; however, they will remain volatile in the future depending on supply, transportation alternatives and refining demand. The Company's average natural gas sales price was $2.24 per Mcf in the third quarter of 2012 compared to $3.85 per Mcf in the third quarter of 2011. The AECO average daily spot natural gas price in April 2012 of $1.58 per GJ reached lows not seen in western Canada since 1996. The AECO average daily spot natural gas price has since increased to an average of $2.94 per GJ in October 2012. The Company's average NGL price was $51.59 per barrel in the third quarter of 2012 as compared to $66.07 in the third quarter of 2011. Average propane and butane prices were significantly lower in the third quarter of 2012 as compared to the third quarter of 2011. NGL prices received as a ratio of oil prices have decreased since 2011. NGL prices as a percentage of oil prices received were 64% in the third quarter of 2012 compared to 74% in the third quarter of 2011. COMMODITY HEDGING CONTRACTSCrude Oil. As part of its price management strategy, the Company has fixed price swap contracts based on the NYMEX crude oil price in Canadian dollars. Subsequent to September 30, 2012, Anderson settled 500 bpd of these hedges for the last two months of the year and realized a gain of $0.4 million which will be reflected in the financial results for the fourth quarter of 2012. As of November 12, 2012, the average volumes and prices for the remaining contracts are summarized below:PeriodWeighted average volume (bpd)Weighted average WTI Canadian ($/bbl)October 20121,500$103.87November to December 20121,000$104.30By comparison, WTI Canadian averaged $91.70 per bbl in the third quarter and $88.36 per bbl in October 2012. During the third quarter of 2012, the Company realized a gain of $0.1 million on its physical sales contracts to sell 7,000 GJs per day of natural gas for August and September 2012 at an average AECO price of $2.45 per GJ, which is included in oil and gas sales. The Company has entered into hedging contracts to protect its balance sheet and will continue to evaluate the merits of additional commodity hedging as part of a price management strategy. PRODUCTION Production in the third quarter of 2012 was 5,770 BOED (68% natural gas). Properties disposed of in the third and fourth quarters of 2012 contributed approximately 1,700 BOED (75% natural gas) of production to the third quarter of 2012. Oil and natural gas liquids production averaged 1,850 bpd. Overall production was lower in the third quarter of 2012 as compared to the same period in 2011 due to natural declines in natural gas properties, the shut-in of higher operating expense natural gas properties and property dispositions. The Company has a relatively low and continuously flattening base production decline rate of approximately 20% per year. This oil and gas production is relatively free of co-produced water which further attests to the quality and stability of this production stream which originates from tight, layered oil and gas reservoirs. In response to the lowest natural gas prices of the last 16 years, the Company has approximately 700 Mcfd of natural gas production with high operating costs shut-in. The Company is monitoring natural gas prices to determine when these wells could be returned to production. In addition, the Company has 3.1 MMcfd of proved developed non-producing gas that could be brought on-stream at various price points.HORIZONTAL OIL PROSPECT INVENTORY The Company's drilled and drill ready tight oil inventory suited to horizontal exploitation is outlined below:Cardium Prospect AreaGrossNet *Garrington11484Willesden Green7857Ferrier2315Pembina3115Total Cardium inventory246171Horizontal prospect inventory in other zones8746Total Cardium and other zone horizontal inventory333217Oil wells drilled to November 12, 20127354Remaining Cardium and other zone inventory, November 12, 2012260163* Net is net revenue interest Anderson has completed all of its Cardium facility construction projects. Future wells drilled from the Cardium and much of the other zone inventory outlined above could be simply connected to the new Company-owned infrastructure. FACILITIES UPDATE The upgrade of the Garrington battery at 15-34-035-03 W5 to accommodate trucked in oil from both owned and third party sources is now complete. The Company receives processing fee income at this facility which offsets a portion of the operating costs of the facility. This 100% owned facility is strategic in mitigating pipeline interruptions in other Cardium oil fields by trucking to this facility which is connected to the Rangeland pipeline system. RESERVES GLJ, an independent reserves evaluator, has completed an interim reserves report of all of the Company's oil and natural gas properties effective October 1, 2012, prepared in accordance with procedures and standards contained in the Canadian Oil and Gas Evaluation ("COGE") Handbook. This reserves report was completed for the Company's bank syndicate and includes properties sold in the fourth quarter of 2012. This is not a year end reserves report. GLJ will update this report for fourth quarter activities with an appropriate January 2013 price forecast for year end reserves reporting. 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. As of October 1, 2012, the Company has 14.5 MMBOE total proved (32% oil and NGL) and 25.3 MMBOE proved plus probable (35% 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, 2012. PROPERTY DISPOSITIONS Since September 30, 2012, Anderson has sold or agreed to sell approximately 1,560 BOED of production (75% natural gas) for cash consideration of $37.5 million subject to normal closing adjustments. Since January 1, 2012, the Company has sold or agreed to sell interests in 17 properties for total consideration of $74 million (subject to normal course closing adjustments). Total production sold or agreed to be sold was approximately 2,292 BOED (71% natural gas) and includes 54 BOED of dry gas swapped in exchange for additional interests in Cardium drillable lands at Garrington. Anderson has sold almost its entire position in W4M, exited the outside operated coal bed methane business and remains focused exclusively on its W5M assets. Anderson has retained its position in both the large, well established Cardium light oil play and the emerging Second White Specs light oil play. STRATEGY AND OUTLOOK Subject to the outcome of the strategic alternatives process described below, the Company continues to focus on converting its core central Alberta asset base to be more than 50% oil and NGL production. Since the first quarter of 2012, the Company has been focused on the divestiture of primarily non-strategic gas-weighted properties to help achieve this goal, as well as to reduce bank debt. The level of capital expenditures in the fourth quarter of 2012 will be commensurate with corporate cash flow projections, the extent of property dispositions and available bank lines. The Company has resumed drilling in the fourth quarter with one well drilled to date since September 30, 2012. Anderson is encouraged that natural gas pricing has recently strengthened in response to a reduction in North American gas directed drilling activity, as well as a warmer than normal summer in the United States resulting in higher electrical generation demand. Normal winter temperatures in 2012/2013 could help to strengthen natural gas pricing, however, this could be offset by an increase in industry drilling activity. Oil prices continue to fluctuate according to the level of the geopolitical premium on top of fundamental supply and demand considerations. The Company benefits from being almost fully hedged for crude oil for the balance of 2012. As part of the Company's risk management policy, both oil and gas hedging opportunities are continuously evaluated. The Company previously filed a Form 15 with the U.S. Securities and Exchange Commission (the "SEC") to temporarily suspend the Company's SEC reporting obligations, and now intends to file a Form 15F with the SEC to terminate those obligations. The Company continues to be listed on the Toronto Stock Exchange. STRATEGIC ALTERNATIVES As previously announced, the Board of Directors is conducting a process to identify, examine and consider a range of strategic alternatives available to the Company with a view to enhancing shareholder value. The strategic alternatives considered may include, but are not limited to, a sale of all or a material portion of the assets of Anderson, either in one transaction or in a series of transactions, the outright sale of the Company, or a merger or other strategic transaction involving Anderson and a third party. The Board of Directors believes that the Company's shares trade at a significant discount to the value of the underlying assets, especially given its high quality oil production base, prospective horizontal oil drilling inventory and significant tax pools. The Board of Directors has established a special committee comprised of independent directors of the Company to oversee this process and has retained BMO Capital Markets and RBC Capital Markets as its financial advisors to assist the Special Committee and the Board of Directors with the process. The process was not initiated as a result of any particular offer. Since January 1, 2012, the Company has sold or has agreed to sell approximately $74 million of oil and gas properties. It is Anderson's current intention to not disclose developments with respect to its strategic alternatives process unless and until the Board of Directors has approved a specific transaction or otherwise determines that disclosure is necessary in accordance with applicable law. The Company cautions that there are no assurances or guarantees that the process will result in a transaction or, if a transaction is undertaken, the terms or timing of such a transaction. The Company has not set a definitive schedule to complete its evaluation.CORPORATE OFFICE MOVE The Company is moving its corporate office effective November 26, 2012 to 2200, 333 - 7th Avenue SW, Calgary, Alberta, T2P 2Z1.Brian H. Dau, President & Chief Executive Officer November 13, 2012Management's Discussion and Analysis FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2012 AND 2011The following management's discussion and analysis ("MD&A") is dated November 12, 2012 and should be read in conjunction with the unaudited condensed interim consolidated financial statements of Anderson Energy Ltd. ("Anderson" or the "Company") for the three and nine months ended September 30, 2012 and the audited consolidated financial statements and management's discussion and analysis of Anderson for the years ended December 31, 2011 and 2010. 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 sales plus realized gains/losses on derivative contracts less royalties, operating expenses and transportation expenses and is a measure of the profitability of operations before administrative, financing, depletion and depreciation expenses. 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. Although 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, BOE's 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. In recent years, the value ratio based on the price of crude oil as compared to natural gas has been significantly higher than the energy equivalency of 6:1 and utilizing a conversion of natural gas volumes on a 6:1 basis may be misleading as an indication of value. These terms are not defined by International Financial Reporting Standards ("IFRS") and therefore are referred to as non-GAAP measures. All references to dollar values are to Canadian dollars unless otherwise stated. Production volumes are measured upon sale unless otherwise noted. Definitions of the abbreviations used in this discussion and analysis are located on the last page of this document. REVIEW OF FINANCIAL RESULTSOverview. Anderson has made significant improvements to its statement of financial position during 2012. Proceeds from the disposition of properties have been used to pay down bank loans, reduce the working capital deficiency and fund a modest level of capital spending. However, the dispositions have contributed to lower production volumes and related cash flows from operations. The natural declines of oil and gas production, shut-ins of uneconomic gas production, lower capital spending during 2012 and comparatively lower commodity prices have also impacted operating and financial results for the three and nine months ended September 30, 2012 compared to the same periods ended in 2011. Bank loans plus cash working capital deficiency decreased from $132.7 million since December 31, 2011 to $97.0 million at September 30, 2012. As previously disclosed, Anderson has entered into agreements to sell additional properties for cash consideration of $37.5 million (subject to normal course closing adjustments). Approximately one-half of these dispositions have now closed and the remainder is scheduled to close before the end of November 2012, at which point the Company's bank lines will step down to $70 million from $98 million at September 30, 2012. Pro forma the close of these transactions, outstanding bank loans at September 30, 2012 would be $51.4 million (bank loans and working capital deficiency - $59.5 million.) Funds from operations of $5.7 million for the third quarter of 2012 were 55% lower than the third quarter of 2011 as a result of the substantial drop in natural gas prices (42% decrease), declines in oil prices (10% decrease) and overall lower production volumes (22% decrease). Funds from operations for the third quarter of 2012 were $1.9 million lower than the second quarter of 2012 primarily due to reduced production volumes (15% decrease). The Company did not drill any new wells in the third quarter. Revenue and Production. During the nine months ended September 30, 2012, Anderson sold interests in 13 properties for total consideration of $36.9 million. Total production sold was approximately 678 BOED (59% natural gas), and is considered by the Company to be non-strategic. The Company has swapped an additional 54 BOED of dry gas in exchange for additional interests in Cardium drillable lands at Garrington. During the third quarter of 2012, Anderson sold approximately 428 BOED (51% natural gas) for cash consideration of $30.7 million. Subsequent to September 30, 2012, Anderson has sold or agreed to sell an additional 1,560 BOED of production (75% natural gas) for cash consideration of $37.5 million (subject to normal closing adjustments). Since January 1, 2012, the Company has sold or agreed to sell interests in 17 properties for total consideration of $74 million (subject to normal course closing adjustments). Total production sold or agreed to be sold was approximately 2,292 BOED (71% natural gas) and includes 54 BOED of dry gas swapped in exchange for additional interests in Cardium drillable lands at Garrington. Oil and natural gas liquids, which have higher sales prices and operating netbacks than natural gas, continue to take a larger role in the Company's sales mix. Oil and natural gas liquids represented 72% of oil and gas sales in the third quarter of 2012, down from 79% in the second quarter of 2012 and up 9% from the third quarter of 2011. For the nine months ended September 30, 2012, oil and natural gas liquids represented 77% of oil and gas sales compared to 62% in the comparable period in 2011. Oil production for the third quarter of 2012 averaged 1,274 bpd compared to 1,669 bpd in the second quarter of 2012 and 1,709 bpd for the third quarter of 2011. The decrease in volumes from the second quarter of 2012 is due to property dispositions in the quarter and natural production declines as no new wells have been drilled since the first quarter of 2012. For the first nine months of 2012, oil sales averaged 1,632 bpd compared to 1,615 bpd in the comparable period of 2011. The higher oil production in 2012 compared to 2011 is the result of Anderson's focus on Cardium oil development. The Company suspended its shallow gas drilling program after the first quarter of 2010 because of low natural gas prices. Accordingly, natural production declines have not been replaced, resulting in decreases in gas sales throughout 2011 and 2012. In addition, as a result of the low prices, Anderson has shut-in approximately 700 Mcfd of natural gas production with high operating costs and has sold some non-strategic assets. Gas sales volumes continued to decline in the third quarter of 2012 to 23.5 MMcfd from 26.4 MMcfd in the second quarter of 2012. Gas sales volumes for the nine months ended September 30, 2012 were 25.8 MMcfd compared to 32.0 MMcfd for the same period of 2011. Natural gas liquids sales for the three months ended September 30, 2012 averaged 576 bpd compared to 750 bpd in the second quarter of 2012 and 636 bpd for the third quarter of 2011. For the nine months ended September 30, 2012, natural gas liquids sales averaged 676 bpd compared to 667 bpd in the first nine months of 2011. The following tables outline oil and natural gas sales, volumes and average sales prices for the three and nine month periods ended September 30, 2012 and 2011. OIL AND NATURAL GAS SALESThree months ended September 30Nine months ended September 30(thousands of dollars)2012201120122011Natural gas$4,707$9,834$13,869$31,788Gain on fixed price natural gas contracts136818136818Oil(1)9,43214,00237,56840,377NGL2,7333,86310,75412,517Royalty and other5(4)205165Total oil and gas sales(1)$17,013$28,513$62,532$85,665(1)The three months ended September 30, 2012 excludes the realized gain and unrealized gain (loss) on derivative contracts of $1.7 million and ($2.7) million respectively (September 30, 2011 - $0.9 million and $6.4 million respectively).The nine months ended September 30, 2012 excludes the realized gain (loss) and unrealized gain on derivative contracts of $3.2 million and $0.3 million respectively (September 30, 2011 - ($0.4) million and $11.2 million respectively).PRODUCTIONThree months ended September 30Nine months ended September 302012201120122011Natural gas (Mcfd)23,51930,03825,79931,972Oil (bpd)1,2741,7091,6321,615NGL (bpd)576636676667Total (BOED)5,7707,3516,6077,610PRICESThree months ended September 30Nine months ended September 302012201120122011Natural gas ($/Mcf)$2.24$3.85$1.98$3.74Oil ($/bbl)(1)80.4489.0584.0391.59NGL ($/bbl)51.5966.0758.0668.76Total ($/BOE)(1)(2)$32.05$42.16$34.54$41.23(1)Excludes realized and unrealized gains and losses on derivative contracts. (2)Includes royalty and other income classified with oil and gas sales.World and North American benchmark prices for oil remain volatile and as described below, the Company has entered into certain derivative contracts to partially hedge oil prices. Differentials between WTI oil prices and prices received in Alberta are affected by factors including refining demand and pipeline capacity. Light, sweet oil differentials between Cushing, Oklahoma and Edmonton, Alberta were an average $7.21 per bbl U.S. discount in the third quarter of 2012, $10.25 per bbl U.S. in the second quarter of 2012 and $10.53 per bbl U.S. discount in the first quarter of 2012, compared to an average $1.46 per bbl U.S. premium as recently as the fourth quarter of 2011. In the fourth quarter of 2012, light sweet, oil differentials are expected to be comparable on average to the third quarter of 2012 and may remain volatile in the future depending on supply, transportation alternatives and refining demand. Natural gas prices were low throughout 2011. Market conditions, including high supply and low demand due to a warm winter in North America, resulted in another step change reduction in natural gas prices during the first six months of 2012. However, the increased demand for natural gas for electrical power generation during the hot summer throughout North America has contributed to some recent price gains. For the three months ended September 30, 2012, the above noted oil prices do not include a realized gain on derivative contracts of $1.7 million (September 30, 2011 - $0.9 million). The realized oil price including the realized gains was $94.76 per barrel for the third quarter of 2012 compared to $94.58 per barrel for the third quarter of 2011. For the nine months ended September 30, 2012, the above noted oil prices do not include a realized gain on derivative contracts of $3.2 million (September 30, 2011 - $0.4 million loss). The realized oil price including realized gains (losses) was $91.18 per barrel for the first nine months of 2012 compared to $90.79 per barrel for the first nine months of 2011. The Company's average natural gas sales price was $2.24 per Mcf for the three months ended September 30, 2012, 30% higher than the second quarter of 2012 price of $1.72 per Mcf and 42% lower than the third quarter of 2011 price of $3.85 per Mcf. For the nine months ended September 30, 2012, the Company's average natural gas sales price was $1.98 per Mcf compared to $3.74 per Mcf for the first nine months of 2011. The natural gas price in the third quarter of 2012 includes a gain of $0.1 million on the Company's fixed price natural gas contracts, compared to a gain of $0.8 million in the third quarter of 2011. The third quarter gas price before the gain was an average of $2.18 per Mcf compared to $3.56 per Mcf in the third quarter of 2011Commodity Contracts. At September 30, 2012, the following derivative contracts were outstanding and recorded at estimated fair value:PeriodWeighted average volume (bpd)Weighted average WTI Canadian ($/bbl)October 1, 2012 to December 31, 20121,500103.87In October 2012, 500 bpd of derivative contracts for the months of November and December 2012 were settled for a gain of $0.4 million which will be reflected in the financial results for the fourth quarter of 2012. By comparison, WTI Canadian averaged $103.04 per bbl in the first quarter of 2012, $94.29 per bbl in the second quarter of 2012, $91.70 per bbl in the third quarter and $88.36 per bbl in October 2012. Derivative contracts had the following impact on the consolidated statements of operations and comprehensive loss for the three and nine months ended September 30, 2012 and 2011:Three months ended September 30Nine months ended September 30(thousands of dollars)2012201120122011Realized gain (loss) on derivative contracts$1,680$871$3,198$(353)Unrealized gain (loss) on derivative contracts(2,656)6,35034711,166$(976)$7,221$3,545$10,813Fixed Price Contracts. The Company entered into physical contracts to sell 7,000 GJs per day of natural gas for August and September 2012 at an average AECO price of $2.45 per GJ. The Company realized a gain on fixed price natural gas contracts of $0.1 million for the three and nine months ended September 30, 2012 as compared to a gain of $0.8 million for the three and nine months ended September 30, 2011.Royalties. For the third quarter of 2012, the average royalty rate was 10.2% of oil and gas sales compared to 10.0% in the second quarter of 2012 and 12.4% in the third quarter of 2011. For the first nine months of 2012, the average royalty rate was 10.4% of revenue compared to 11.2% in the first nine months of 2011. Royalty rates quarter over quarter have declined slightly as a result of lower commodity prices.Royalties as a percentage of total oil and gas sales are highly sensitive to prices and adjustments to gas cost allowance and so royalty rates can fluctuate from quarter to quarter.Three months ended September 30Nine months ended September 302012201120122011Gross Crown royalties7.0%10.3%8.3%9.6%Gas cost allowance(2.5%)(5.5%)(3.9%)(5.3%)Other royalties5.7%7.6%6.0%6.9%Total royalties10.2%12.4%10.4%11.2%Royalties ($/BOE)$3.26$5.24$3.60$4.64Operating Expenses. Operating expenses were $11.28 per BOE for the three months ended September 30, 2012 compared to $10.06 per BOE in the second quarter of 2012 and $11.22 per BOE in the third quarter of 2011. Operating expenses were $10.62 per BOE for the nine months ended September 30, 2012 compared to $11.30 per BOE in same period in 2011. The decrease in operating expenses for the nine months ended September 30, 2012 relative to the comparable periods in 2011 is due to the completion of infrastructure built for new wells drilled throughout 2011 and early 2012, resulting in more efficient operations and lower costs. The impact of the lower costs from this infrastructure was partially offset during the third quarter of 2012 with the sale of assets and related processing revenues that were netted from operating expenses.Transportation Expenses. For the three months ended September 30, 2012, transportation expenses were $0.13 per BOE compared $0.89 per BOE in the third quarter of 2011. For the nine months ended September 30, 2012, transportation expenses were $0.25 per BOE compared to $0.63 per BOE for the same period in 2011. The decrease in transportation expenses in 2012 relative to 2011 is due to the direct tie-in of the Garrington battery to a newly constructed lateral pipeline in late October 2011, thereby replacing clean oil trucking charges with a pipeline tariff, which is netted from the Company's oil sales price. OPERATING NETBACK Three months ended September 30Nine months ended September 30(thousands of dollars)2012201120122011Revenue (1)$17,013$28,513$62,532$85,665Realized gain (loss) on derivative contracts1,6808713,198(353)Royalties(1,729)(3,543)(6,513)(9,636)Operating expenses(5,985)(7,590)(19,223)(23,473)Transportation expenses(69)(602)(459)(1,304)Operating netback$10,910$17,649$39,535$50,899Sales (MBOE)530.9676.31,810.42,077.6Per BOERevenue (1)$32.05$42.16$34.54$41.23Realized gain (loss) on derivative contracts3.161.291.77(0.17)Royalties(3.26)(5.24)(3.60)(4.64)Operating expenses(11.28)(11.22)(10.62)(11.30)Transportation expenses(0.13)(0.89)(0.25)(0.63)Operating netback per BOE$20.54$26.10$21.84$24.49(1)Includes royalty and other income classified with oil and gas sales.The three months ended September 30, 2012 excludes the unrealized gain (loss) on derivative contracts of ($2.7) million (September 30, 2011 - $6.4 million).The nine months ended September 30, 2012 excludes the unrealized gain on derivative contracts of $0.3 million (September 30, 2011 - $11.2 million).Depletion and Depreciation. Depletion and depreciation was $10.1 million ($19.01 per BOE) for the third quarter of 2012 compared to $12.3 million ($19.77 per BOE) in the second quarter of 2012 and $12.3 million ($18.16 per BOE) in the third quarter of 2011. Depletion and depreciation expense for the third quarter of 2012 is lower compared to the same period of 2011 due to lower overall production volumes, whereas the depletion and depreciation rate per BOE is higher in 2012 due to the higher capital costs associated with the 2011 and 2012 capital programs. Impairment Loss (Reversal). In the third quarter of 2012, an impairment test was performed on the Company's CGU's and management concluded that no impairment existed at September 30, 2012. In the second quarter of 2012, declines in forecasted natural gas commodity prices and the ongoing strategic alternatives process were indicators of impairment for certain CGUs. Forecasted natural gas commodity prices at June 30, 2012 declined between eight and 18 per cent when compared to December 31, 2011. Accordingly, the Company tested its gas-weighted CGUs for impairment and determined that the aggregate carrying value of these CGUs was $20 million higher than the recoverable amount and impairments were recorded. At 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. 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.General and Administrative Expenses. General and administrative expenses excluding stock-based compensation were $2.1 million ($3.88 per BOE) for the third quarter of 2012 compared to $2.4 million ($3.94 per BOE) in the second quarter of 2012 and $2.6 million ($3.81 per BOE) for the third quarter of 2011. For the nine months ended September 30, 2012, general and administrative expenses excluding stock-based compensation were $6.7 million ($3.68 per BOE) compared to $7.2 million ($3.48 per BOE) for the same period in 2011. The decrease in cash general and administrative expenses is the result of lower employee compensation associated with reduced staff and decreased audit and tax fees as the comparative period in 2011 had higher fees associated with the adoption of IFRS. In the fourth quarter of 2012, the Company laid off some of its staff. One time severance costs of approximately $0.5 million will be recorded in the fourth quarter. Beginning in December 2012, office rent is expected to decrease by $0.1 million per month as a result of the corporate office move.Three months ended September 30Nine months ended September 30(thousands of dollars)2012201120122011General and administrative (gross)$3,152$3,747$10,110$11,440Overhead recoveries(265)(502)(973)(1,312)Capitalized(825)(671)(2,484)(2,895)General and administrative (cash)$2,062$2,574$6,653$7,233Net stock-based compensation143239573730General and administrative$2,205$2,813$7,226$7,963General and administrative (cash) ($/BOE)$3.88$3.81$3.68$3.48% Capitalized26%18%25%25%Capitalized general and administrative costs are limited to salaries and associated office rent of staff involved in capital activities. Stock-based Compensation. The Company accounts for stock-based compensation plans using the fair value method of accounting. Stock-based compensation costs were $0.2 million in the third quarter of 2012 ($0.1 million net of amounts capitalized) compared to $0.4 million for the third quarter of 2011 ($0.2 million net of amounts capitalized). For the nine months ended September 30, 2012, stock-based compensation costs were $0.9 million ($0.6 million net of amounts capitalized) compared to $1.2 million ($0.7 million net of amounts capitalized) in the same period of 2011.Finance Expenses. Finance expenses were $3.9 million in the third quarter of 2012, compared to $3.8 million for the second quarter of 2012 and $3.3 million in the third quarter of 2011. For the nine months ended September 30, 2012, finance expenses were $11.3 million compared to $8.5 million in the same period of 2011. While the average effective interest rate on outstanding bank loans was 4.5% for the nine months ended September 30, 2012 compared to 5.7% for the comparable period in 2011, the Company had higher levels of bank loans outstanding during 2012, leading to the higher finance expenses.Three months ended September 30Nine months ended September 30(thousands of dollars)2012201120122011Interest and accretion on convertible debentures$2,269$2,233$6,765$4,831Interest expense on credit facilities and other1,3526703,6452,394Accretion on decommissioning obligations2424398791,295Finance expenses$3,863$3,342$11,289$8,520Decommissioning Obligations. In the third quarter of 2012, the Company disposed of $6.1 million in decommissioning obligations related to property dispositions, and increased the decommissioning obligations by $2.6 million primarily relating to changes in estimates. Accretion expense was $0.2 million for the third quarter of 2012 compared to $0.4 million in the third quarter of 2011 and was included in finance expenses. For the nine months ended September 30, 2012, the Company disposed of $11.1 million in decommissioning obligations related to property dispositions, and increased the decommissioning obligations by $3.6 million primarily relating to changes in estimates. The risk-free discount rates used by the Company to measure the obligations at September 30, 2012 were between 1.0% and 2.5% depending on the timelines to reclamation compared to 0.9% and 3.1% at December 31, 2011. Income Taxes. Anderson is not currently taxable. The Company estimates that it has approximately $461 million in tax pools at September 30, 2012. Funds from Operations. Funds from operations for the third quarter of 2012 were $5.7 million ($0.03 per share), down 25% from the $7.6 million ($0.04 per share) recorded in the second quarter of 2012 and down 55% from the $12.7 million ($0.07 per share) recorded in the third quarter of 2011. The decrease in funds from operations in the third quarter of 2012 compared to the second quarter of 2012 was largely due to 15% lower production volumes associated with property dispositions and natural production declines. Funds from operations for the nine months ended September 30, 2012 decreased compared to 2011 for due to lower commodity prices for natural gas (47%), oil (8%) and NGL's (16%) in the nine months ended September 30, 2012 versus the nine months ended September 30, 2011. Production declines in natural gas of 19% in the nine months ended September 30, 2012 compared to September 30, 2011 due to natural production declines also contributed to lower funds from operations in 2012.Three months ended September 30Nine months ended September 30(thousands of dollars)2012201120122011Cash from operating activities$5,845$11,893$22,863$37,847Changes in non-cash working capital(147)701692(483)Decommissioning expenditures2761392103Funds from operations$5,725$12,655$23,947$37,467Earnings. The Company reported earnings of $0.1 million in the third quarter of 2012 compared to a loss of $16.8 million for the second quarter of 2012 and earnings of $7.5 million for the third quarter of 2011. In the third quarter of 2012, earnings were impacted by gains recognized on the Company asset dispositions. 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: SENSITIVITIESAnnual Funds from OperationsAnnual EarningsMillionsPer ShareMillionsPer Share$0.50/Mcf in price of natural gas$4.7$0.03$3.5$0.02U.S. $5.00/bbl in the WTI crude price$3.3$0.02$2.5$0.01U.S. $0.01 in the U.S./Cdn exchange rate$1.0$0.01$0.7$0.001% in short-term interest rate$0.6$0.00$0.4$0.00This sensitivity analysis was calculated by applying different pricing, interest rate and exchange rate assumptions to the 2011 actual results related to production, prices, royalty rates, operating costs and capital spending. As the contribution of oil production continues to increase as a percentage of total production, the impact of oil prices will be more significant and the impact of natural gas prices will be less significant to funds from operations and earnings than is shown in the table above. CAPITAL EXPENDITURES Capital expenditures before dispositions were $1.7 million in the third quarter of 2012, and proceeds on disposition were $30.7 million in the third quarter of 2012. The breakdown of expenditures is shown below:Three months ended September 30Nine months ended September 30(thousands of dollars)2012201120122011Land, geological and geophysical costs$50$201$410$3,967Proceeds on disposition(30,710)(6,203)(36,909)(11,570)Drilling, completion and recompletion26243,70014,35095,260Drilling incentive credits-(262)-(400)Facilities and well equipment45711,4367,58428,001Capitalized general and administrative expenses8256712,4842,895Total finding, development & acquisition expenditures(29,116)49,543(12,081)118,153Change in compressor and other inventory and equipment131128(54)128Office equipment and furniture(1)422570Total net cash capital expenditures(28,986)49,713$(12,110)$118,351Drilling statistics are shown below:Three months ended September 30Nine months ended September 302012201120122011GrossNetGrossNetGrossNetGrossNetGas--------Oil--2118.032.54134.2Dry--------Total--2118.032.54134.2Success rate (%)--100%100%100%100%100%100%Subsequent to September 30, 2012, Anderson entered into agreements to sell or closed the sale of approximately 1,560 BOED of production (75% natural gas) for cash consideration of $37.5 million (subject to normal course closing adjustments). Approximately one-half of these dispositions have now closed and the remainder is scheduled to close before the end of November 2012. RESERVES GLJ Petroleum Consultants ("GLJ"), an independent reserves evaluator, has completed an interim reserves report of all of the Company's oil & natural gas properties effective October 1, 2012, prepared in accordance with procedures and standards contained in the Canadian Oil and Gas Evaluation ("COGE") Handbook. This reserves report was completed for the Company's bank syndicate and includes properties sold in the fourth quarter of 2012. This is not a year end reserves report. GLJ will update this report for fourth quarter activities with an appropriate January 2013 price forecast for year end reserves reporting. The reserves definitions used in preparing the interim report are those contained in the COGE Handbook and the Canadian Securities Administrators National Instrument 51-101. As of October 1, 2012, the Company has 14.5 MMBOE total proved ("TP") and 25.3 MMBOE total proved plus probable ("P&P") reserves. Oil and NGL reserves represent 32% of TP and 35% of the P&P reserves as compared to 29% and 31% respectively at December 31, 2011. SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONSAs at October 1, 2012 GLJ Forecast Prices and CostsOilNatural GasEdmonton Liquids PricesYearWTI Cushing ($US/bbl)Light, Sweet Crude Edmonton ($Cdn/bbl)AECO Gas Price ($Cdn/Mcf)Propane ($Cdn/bbl)Butane ($Cdn/bbl)Pentanes Plus ($Cdn/bbl)Inflation Rate %Exchange rate (US$/Cdn)2012 Q492.5090.502.9227.1570.5999.552.01.00201392.5092.353.4446.1772.0398.812.00.98201495.0095.923.9057.5574.8299.762.00.98201597.5098.474.3659.0876.81102.412.00.982016100.00101.024.8260.6178.80105.062.00.982017100.00101.025.0560.6178.80105.062.00.982018101.35102.405.4361.4479.87106.492.00.982019103.38104.475.5462.6881.49108.652.00.982020105.45106.585.6563.9583.13110.842.00.982021107.56108.735.7665.2484.81113.082.00.98Thereafter 2%SHARE INFORMATION The Company's shares have been listed on the Toronto Stock Exchange since September 7, 2005 under the symbol "AXL". As of November 12, 2012, there were 172.5 million common shares outstanding, 15.2 million stock options outstanding and $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. Approximately 0.6 million stock options are scheduled to expire by the end of November 2012. During the third quarter of 2012 and 2011, there were no common shares issued under the employee stock option plan.Three months ended September 30Nine months ended September 302012201120122011High$0.35$0.87$0.68$1.36Low$0.21$0.42$0.21$0.42Close$0.23$0.43$0.23$0.43Volume8,042,34923,739,99532,883,171108,708,081Shares outstanding at September 30172,549,701172,549,701172,549,701172,549,701Market capitalization at September 30$39,686,431$74,196,371$39,686,431$74,196,371The 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 months and nine months ended September 30, 2012 approximately 4.8 million and 15.3 million common shares traded on these alternative exchanges respectively. Including these exchanges, an average of 0.2 million common shares traded per day in the third quarter of 2012 (September 30, 2011 - 0.6 million), representing a quarterly turnover ratio of 7% (September 30, 2011 - 20%). The Company previously filed a Form 15 with the U.S. Securities and Exchange Commission (the "SEC") to temporarily suspend the Company's SEC reporting obligations, and now intends to file a Form 15F with the SEC to terminate those obligations. The Company continues to be listed on the Toronto Stock Exchange. LIQUIDITY AND CAPITAL RESOURCES At September 30, 2012, the Company had outstanding bank loans of $88.9 million, convertible debentures of $96.0 million (principal) and a cash working capital deficiency (excluding unrealized gain on derivative contracts) of $8.1 million. The working capital deficiency includes $1.5 million of interest on convertible debentures which is paid semi-annually, with the next payment due at the end of December 2012. The following table shows the changes in bank loans plus cash working capital deficiency: Three months ended September 30Nine months ended September 30(thousands of dollars)2012201120122011Bank loans plus cash working capital deficiency, beginning of period$(131,675)$(71,464)$(132,656)$(71,507)Funds from operations5,72512,65523,94737,467Net cash capital (expenditures) proceeds28,986(49,713)12,110(118,351)Proceeds from issue of convertible debentures, net of issue costs---43,860Proceeds from exercise of stock options---51Decommissioning expenditures(27)(61)(392)(103)Bank loans plus cash working capital deficiency, end of period$(96,991)$(108,583)$(96,991)$(108,583)Successful future operations of the Company are dependent on the ability of the Company to secure sufficient funds through operations, the proceeds from the disposition of non-strategic assets or other sources from the strategic alternatives process. 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. The Company is funding its 2012 capital program from a combination of cash flow and the proceeds from the sale of non-strategic assets. The Company has actively pursued the sale of its non-strategic assets. The extent of the capital program in the fourth quarter will be dependent on the property disposition program, oil and natural gas prices and available credit facilities. Subsequent to September 30, 2012, Anderson sold or agreed to sell oil and gas properties for cash consideration of $37.5 million, subject to normal course closing adjustments. Pro forma the dispositions, bank loans would be $51.4 million and bank loan plus working capital deficiency would be $59.5 million at September 30, 2012. At September 30, 2012, the Company had total credit facilities of $98 million, consisting of an $88 million revolving term credit facility and a $10 million working capital credit facility with a syndicate of Canadian banks. Upon completion of the previously disclosed disposition transactions that are scheduled to close by the end of November 2012, the Company's bank lines will step down to $70 million. If not extended, the revolving term credit facility and working capital credit facility cease to revolve and all outstanding advances become repayable on July 10, 2013. Advances 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 3% to 4% depending on the borrowing option used. At September 30, 2012, no amounts were drawn in U.S. funds. The available lending limits of the facilities are scheduled to be reviewed on or before December 15, 2012 and are based on the bank syndicate's interpretations of the Company's reserves and future commodity prices. There can be no assurance that the amount of the available facilities or the applicable margins will not be adjusted as a result of future dispositions, changes in reserve values, future commodity prices or at the next scheduled review.OFF BALANCE SHEET ARRANGEMENTS The Company had no guarantees or off balance sheet arrangements other than as described below under "Contractual Obligations". CONTRACTUAL OBLIGATIONS The Company enters into various contractual obligations in the course of conducting its operations. The obligations noted below are updates as at September 30, 2012 to the obligations disclosed in the management's discussion and analysis of Anderson for the years ended December 31, 2011 and 2010 and should be read in conjunction with that document:Loan agreements - The reserves-based revolving term credit facility and working capital credit facility have a maturity date of July 10, 2013. If not renewed, all outstanding advances thereunder become repayable on July 10, 2013. Firm service transportation commitments - The Company has entered into firm service transportation agreements for approximately 15 million cubic feet per day of gas sales for various terms expiring between 2012 and 2020. Cardium Horizontal Well Program (Oil) - The Company has farm-in obligations to drill four gross (3.9 net capital) horizontal wells in the Cardium geological formation prior to the end of 2012. One agreement has a $100,000 non-performance fee clause should the Company fail to drill the well. Another agreement pertains to two wells; there is a $35,000 non-performance fee should the Company fail to drill both wells, and if only one well is drilled, the Company would also forfeit fifty per cent of the interest in the first well drilled under the agreement; in a second agreement pertaining to one of these wells, there is also a $25,000 non-performance fee should the Company fail to drill the well. In a third agreement, there is a $200,000 non-performance fee should the Company fail to drill the well. One gross (1 net capital) well has been drilled subsequent to September 30, 2012. New head office lease - Subsequent to September 30, 2012, the Company entered into an agreement to lease office space at a rate of approximately $560,000 per year starting December 1, 2012 and ending June 30, 2014. There are no material changes to other commitments and contingencies from those disclosed in the Company's annual Management's Discussion and Analysis for the years ended December 31, 2011 and 2010. CONTROLS AND PROCEDURES The 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. 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 RISKS Oil 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 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. Differentials between WTI oil prices and prices received in Alberta have widened and also remain volatile. 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 most recent Annual Information Form 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. BUSINESS PROSPECTS The Company believes it has an excellent future drilling inventory in the Cardium horizontal light oil play and is focused on growing its production and reserves with Cardium horizontal drilling. The Company has identified an inventory of 333 gross (217 net revenue) drill-ready Cardium and other horizontal zone oil locations, of which 73 gross (54 net revenue) have been drilled to November 12, 2012. Historically, the Company has added 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. STRATEGY Subject to the outcome of the strategic alternatives process described below, the Company continues to focus on converting its asset base to be more than 50% oil and NGL production. Anderson has a substantial Cardium drilling inventory and with the completion of infrastructure projects in the last year, newly drilled Cardium horizontal wells can be easily connected to these gathering systems. In response to low natural gas prices, the Company has approximately 700 Mcfd of natural gas production with high operating costs shut-in. In a higher price environment, these natural gas wells could easily be returned to production. In addition, the Company has 3.1 MMcfd of proved developed non-producing gas that could be brought on-stream at various price points.Commodity prices are volatile and Anderson continues to look at hedging opportunities to help protect its capital program and its shareholders from volatile markets. STRATEGIC ALTERNATIVES As previously announced, in response to the lack of market recognition of the inherent value in the Company's asset base, the Company's board of directors (the "Board of Directors") is conducting a process to identify, examine and consider a range of strategic alternatives with a view to enhancing shareholder value. The strategic alternatives considered may include, but are not limited to, a sale of all or a material portion of the assets of Anderson, either in one transaction or in a series of transactions, the outright sale of the Company, or a merger or other strategic transaction involving Anderson and a third party. The Board of Directors believes that the Company's shares trade at a significant discount to the value of the underlying assets, especially given its high quality Cardium oil production base, prospective Cardium horizontal oil drilling inventory and significant tax pools. The Board of Directors has established a special committee comprised of independent directors of the Company to oversee this process and has retained financial advisors to assist the Special Committee and the Board of Directors with the process. This process has not been initiated as a result of any particular offer. Since January 1, 2012, Anderson has sold or agreed to sell interests in 17 properties for total consideration of approximately $74 million (subject to normal closing adjustments). Total production sold or agreed to be sold was 2,292 BOED (71% natural gas), including 54 BOED of dry gas swapped in exchange for additional interests in Cardium drillable lands at Garrington, and is considered by the Company to be non-strategic. Anderson has sold almost its entire position in W4M, exited the outside operated coal bed methane business and remains focused exclusively on its W5M assets. The Company has additional non-strategic assets which it is currently marketing to improve its financial flexibility and to focus its resources on its core oil assets. It is Anderson's current intention to not disclose developments with respect to its strategic alternatives process unless and until the Board of Directors has approved a specific transaction or otherwise determines that disclosure is necessary in accordance with applicable law. The Company cautions that there are no assurances or guarantees that the process will result in a transaction or, if a transaction is undertaken, the terms or timing of such a transaction. The Company has not set a definitive schedule to complete its evaluation. On April 1, 2012, the Company implemented a retention plan for its employees as part of this process, which was updated in October 2012 in conjunction with the lay-off of some of its staff. QUARTERLY INFORMATION The 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 year reflect the benefits from increased sales of crude oil volumes. Since 2010, earnings have been affected by impairments in the value of property, plant and equipment related to natural gas reserves values. As discussed above, revenues and funds from operations in the third quarter of 2012 were affected by lower natural gas prices, larger differentials between WTI and Alberta oil prices and lower production volumes. The disposition of properties has reduced the volumes, revenues and operating costs during the second and third quarters of 2012. SELECTED QUARTERLY INFORMATION($ amounts in thousands, except per share amounts and prices)Q3 2012Q2 2012Q1 2012Q4 2011Revenue, net of royalties$15,284$18,290$22,445$28,457Funds from operations$5,725$7,606$10,616$16,997Funds from operations per share, basic and diluted$0.03$0.04$0.06$0.10Earnings (loss) before effect of impairments$94$(1,828)$(5,864)$(4,939)Earnings (loss) per share before effect of impairments basic and diluted$-$(0.01)$(0.03)$(0.03)Earnings (loss)$94$(16,828)$(5,864)$(32,167)Earnings (loss) per share, basic and diluted$-$(0.10)$(0.03)$(0.19)Capital expenditures, including acquisitions net of (proceeds) on dispositions$(28,986)$4,786$12,090$40,924Cash from operating activities$5,845$7,712$9,306$16,462Daily salesNatural gas (Mcfd)23,51926,43827,46330,576Oil (bpd)1,2741,6691,9562,122NGL (bpd)576750703715BOE (BOED)5,7706,8257,2367,933Average pricesNatural gas ($/Mcf)$2.24$1.72$2.01$3.20Oil ($/bbl)(2)$80.44$81.58$88.48$96.33NGL ($/bbl)$51.59$54.38$67.36$72.71BOE ($/BOE)(1)(2)$32.05$32.70$38.28$44.70Q3 2011Q2 2011Q1 2011Q4 2010Revenue, 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)Earnings (loss) per share, basic and diluted$0.04$0.03$(0.02)$(0.21)Capital expenditures, including acquisitions net of proceeds on dispositions$49,713$26,284$42,354$26,240Cash from operating activities$11,893$14,953$11,001$10,488Daily salesNatural gas (Mcfd)30,03831,99033,93138,479Oil (bpd)1,7091,7591,372992NGL (bpd)636667699823BOE (BOED)7,3517,7587,7268,228Average pricesNatural gas ($/Mcf)$3.85$3.79$3.58$3.48Oil ($/bbl)(2)$89.05$99.39$84.71$77.62NGL ($/bbl)$66.07$74.24$65.97$58.87BOE ($/BOE)(1)(2)$42.16$44.71$36.80$31.63(1)Includes royalty and other income classified with oil and gas sales. (2)Excludes realized and unrealized gains (losses) on derivative contracts as follows: Q3 2012 - $1.7 million and ($2.7) million respectively; Q2 2012 - $1.3 million and $4.7 million respectively; Q1 2012 - $0.2 million and ($1.7) million respectively; Q4 2011 - ($0.3) million and ($7.9) million respectively; Q3 2011 - $0.9 million and $6.4 million respectively; Q2 2011 - ($0.8) million and $7.7 million respectively; Q1 2011 - ($0.4) million and ($2.8) million respectively; and Q4 2010 - ($0.1) million and ($1.9) million respectively.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; estimates of future revenues, costs, netbacks, funds from operations and debt levels; the expected proceeds from disclosed asset dispositions and uses thereof, the timing of completion of disclosed asset dispositions, potential results of the strategic alternatives review process, including the possibility of further asset dispositions and use of proceeds therefrom, and enhancement of shareholder value, disclosure intentions with respect to the strategic alternatives review process; factors on which the successful future operations of Anderson are dependent, 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; unexpected decline rates in wells; 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; inability to complete property dispositions or to complete them at anticipated values; 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 securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) or at Anderson's website (www.andersonenergy.ca). 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, 2012December 31, 2011ASSETSCurrent assets:Cash$-$1Accounts receivable and accruals11,03814,272Prepaid expenses and deposits1,9962,326Unrealized gain on derivative contracts (note 12)1,7311,38414,76517,983Deferred tax asset42,73035,389Property, plant and equipment (notes 3, 4)336,366406,947$393,861$460,319LIABILITIES AND SHAREHOLDERS' EQUITYCurrent liabilities:Accounts payable and accruals$21,103$60,573Bank loans (note 5)88,922-110,02560,573Bank loans (note 5)-88,682Convertible debentures86,24784,796Decommissioning obligations (note 6)55,83862,848252,110296,899Shareholders' equity:Share capital (note 7)171,460171,460Equity component of convertible debentures5,0195,019Contributed surplus10,3149,385Deficit (note 7)(45,042)(22,444)141,751163,420Future operations (note 1)Subsequent events (notes 5, 7, 12, 13, 14)Commitments and contingencies (note 13)$393,861$460,319See accompanying notes to the condensed interim consolidated financial statements.ANDERSON ENERGY LTD.Consolidated Statements of Operations and Comprehensive Loss(Stated in thousands of dollars, except per share amounts)(Unaudited)Three months ended September 30Nine months ended September 302012201120122011Oil and gas sales$17,013$28,513$62,532$85,665Royalties(1,729)(3,543)(6,513)(9,636)Revenue, net of royalties15,28424,97056,01976,029Other income (note 9)7,10410,6977,62615,43522,38835,66763,64591,464Operating expenses5,9857,59019,22323,473Transportation expenses696024591,304Depletion and depreciation10,09312,28035,41137,976Impairment loss (reversal) (note 4)-(1,074)20,000(1,074)General and administrative expenses2,2052,8137,2267,963Earnings (loss) from operating activities4,03613,456(18,674)21,822Finance income (note 10)-212454Finance expenses (note 10)(3,863)(3,342)(11,289)(8,520)Net finance expenses(3,863)(3,321)(11,265)(8,466)Earnings (loss) before taxes17310,135(29,939)13,356Deferred income tax expense (benefit)792,663(7,341)3,633Earnings (loss) and comprehensive income (loss) for the period$94$7,472$(22,598)$9,723Basic and diluted earnings (loss) per share (note 8)$-$0.04$(0.13)$0.06See accompanying notes to the condensed interim consolidated financial statements.ANDERSON ENERGY LTD.Consolidated Statements of Changes in Shareholders' EquityNINE MONTHS ENDED SEPTEMBER 30, 2012 AND 2011(Stated in thousands of dollars, except number of common shares)(Unaudited)Number of common sharesShare capitalEquity component of convertible debenturesContributed surplusRetained earnings (deficit)Total shareholders' equityBalance at January 1, 2011172,485,301$426,925$2,592$7,921$(255,543)$181,895Elimination of deficit (note 7)-(255,543)--255,543-Equity component of convertible debentures, net of tax of $1.5 million--2,427- -2,427Share-based payments---1,155-1,155Options exercised64,40078-(27)-51Earnings for the period----9,7239,723Balance at September 30, 2011172,549,701$171,460$5,019$9,049$9,723$195,251Balance at January 1, 2012172,549,701$171,460$5,019$9,385$(22,444)$163,420Share-based payments---929-929Loss for the period----(22,598)(22,598)Balance at September 30, 2012172,549,701$171,460$5,019$10,314$(45,042)$141,751See accompanying notes to the condensed interim consolidated financial statements.ANDERSON ENERGY LTD.Consolidated Statements of Cash FlowsNINE MONTHS ENDED SEPTEMBER 30, 2012 AND 2011(Stated in thousands of dollars)(Unaudited)20122011CASH PROVIDED BY (USED IN)OPERATIONSEarning (loss) for the period$(22,598)$9,723Adjustments for:Unrealized gain on derivative contracts (note 9)(347)(11,166)Gain on sale of property, plant and equipment (note 9)(4,081)(4,622)Depletion and depreciation35,41137,976Impairment loss (reversal) (note 4)20,000(1,074)Stock-based payments573730Accretion on decommissioning obligations (note 6, 10)8791,295Accretion on convertible debentures (note 10)1,451972Deferred income tax expense (benefit)(7,341)3,633Decommissioning expenditures (note 6)(392)(103)Changes in non-cash working capital (note 11)(692)48322,86337,847FINANCINGIncrease (decrease) in bank loans240(872)Proceeds from issue of convertible debentures, net of issue costs-43,860Proceeds from exercise of stock options-51Changes in non-cash working capital (note 11)(175)(253)6542,786INVESTINGProperty, plant and equipment expenditures(24,799)(129,921)Proceeds from sale of property, plant and equipment36,90911,570Changes in non-cash working capital (note 11)(35,039)33,694(22,929)(84,657)Decrease in cash and cash equivalents(1)(4,024)Cash and cash equivalents, beginning of period14,024Cash, end of period$-$-Interest received in cash$29$54Interest paid in cash$(10,355)$(3,721)See accompanying notes to the condensed interim consolidated financial statements.ANDERSON ENERGY LTD.Notes to the Condensed Interim Consolidated Financial StatementsTHREE AND NINE MONTHS ENDED SEPTEMBER 30, 2012 AND 2011(Tabular amounts in thousands of dollars, unless otherwise stated)(Unaudited)1. REPORTING ENTITYAnderson Energy Ltd. and its wholly-owned subsidiaries (collectively "Anderson" or the "Company") are engaged in the acquisition, exploration and development of oil and gas properties in western Canada. Anderson is a public company incorporated and domiciled in Canada. Anderson's common shares and convertible debentures are listed on the Toronto Stock Exchange. The Company's registered office and principal place of business is 700, 555 - 4th Avenue S.W., Calgary, Alberta, Canada, T2P 3E7. Effective November 26, 2012, the Company's registered office and principal place of business will be 2200, 333 - 7th Avenue S.W., Calgary, Alberta, Canada, T2P 2Z1.The Company's Board of Directors is conducting a process to identify, examine and consider a range of strategic alternatives available to the Company with a view to enhancing shareholder value. The strategic alternatives include, but are not limited to, a sale of all or a material portion of the assets of Anderson, either in one transaction or in a series of transactions, the outright sale of the Company, or a merger or other strategic transaction involving Anderson and a third party. The strategic review process is still ongoing and the Company will continue to identify, examine and consider a full range of strategic alternatives. Since January 1, 2012, the Company has sold or has agreed to sell approximately $74 million of oil and gas properties, including approximately $37.5 million (subject to normal course closing adjustments) subsequent to September 30, 2012. Pro forma the close of these transactions, outstanding bank loans at September 30, 2012 would be $51.4 million (bank loans and working capital deficiency - $59.5 million.)It is Anderson's current intention to not disclose developments with respect to its strategic alternatives process unless and until its Board of Directors has approved a specific transaction or otherwise determines that disclosure is necessary in accordance with applicable law. The Company cautions that there are no assurances or guarantees that the process will result in a transaction or, if a transaction is undertaken, the terms or timing of such a transaction. The Company has not set a definitive schedule to complete its evaluation.These condensed interim consolidated financial statements have been prepared on a going concern basis which assumes that the Company will be able to realize its assets and discharge its liabilities in the normal course of business. If this assumption were not appropriate, adjustments to these condensed interim consolidated financial statements may be necessary. When assessing the Company's ability to continue on a going concern basis, material uncertainties related to future commodity prices and related cash flows from operations, current debt levels and required capital commitments may cast significant doubt on the Company's ability to continue as a going concern. The successful future operations of the Company are dependent on the ability of the Company to secure sufficient funds through operations, the proceeds from the disposition of non-strategic assets or other sources from the strategic alternatives process.2. BASIS OF PREPARATION(a) Statement of compliance. The condensed interim consolidated financial statements comply with International Accounting Standard 34 Interim Financial Reporting and do not include all of the information required for full annual financial statements. The condensed interim consolidated financial statements were authorized for issuance by the Board of Directors on November 12, 2012.(b) Accounting policies, judgements, estimates and disclosures. In preparing these condensed interim consolidated financial statements, the accounting policies, methods of computation and significant judgements made by management in applying the Company's accounting policies and key sources of estimation uncertainty were the same as those that applied to the audited consolidated financial statements as at and for the years ended December 31, 2011 and 2010. Refer to note 4 for management's estimates of changes in the fair value of its cash generating units ("CGUs").The following disclosures are incremental to those included with the annual audited consolidated financial statements. Certain disclosures that are normally required in the notes to the annual audited consolidated financial statements have been condensed or omitted. These condensed interim consolidated financial statements should be read in conjunction with the Company's audited consolidated financial statements and notes thereto for the years ended December 31, 2011 and 2010. 3. PROPERTY, PLANT AND EQUIPMENTCost or deemed costOil and natural gas assetsOther equipmentTotalBalance at January 1, 2011$585,495$1,779$587,274Additions183,18284183,266Disposals(14,802)-(14,802)Balance at December 31, 2011$753,875$1,863$755,738Additions30,5002530,525Disposals(69,974)-(69,974)Balance at September 30, 2012$714,401$1,888$716,289Accumulated depletion, depreciation and impairment lossesOil and natural gas assetsOther equipmentTotalBalance at January 1, 2011$265,358$1,243$266,601Depletion and depreciation52,79413552,929Impairment loss35,230-35,230Disposals(5,969)-(5,969)Balance at December 31, 2011$347,413$1,378$348,791Depletion and depreciation35,30011135,411Impairment loss20,000-20,000Disposals(24,279)-(24,279)Balance at September 30, 2012$378,434$1,489$379,923Carrying amountsOil and natural gas assetsOther equipmentTotalAt December 31, 2011$406,462$485$406,947At September 30, 2012$335,967$399$336,366Capitalized overhead. For the nine months ended September 30, 2012, additions to property, plant and equipment included internal overhead costs of $3.0 million (year ended December 31, 2011 -$4.6 million). 4. IMPAIRMENT LOSS (REVERSAL)In the third quarter of 2012, there were indicators of impairment due to the ongoing strategic alternatives process. An impairment test was performed on the Company's CGU's and management concluded that no impairment existed at September 30, 2012. In the second quarter of 2012, declines in forecasted natural gas commodity prices and the ongoing strategic alternatives process were indicators of impairment for certain CGUs. Forecasted natural gas commodity prices at June 30, 2012 declined between eight and 18 per cent when compared to December 31, 2011. Accordingly, the Company tested its gas-weighted CGUs for impairment and determined that the aggregate carrying value of these CGUs was $20 million higher than the recoverable amounts and impairments were recorded. At 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. 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.5. BANK LOANSAt September 30, 2012, total bank facilities were $98 million, consisting of an $88 million revolving term credit facility and a $10 million working capital credit facility with a syndicate of Canadian banks. Total bank facilities are stepping down on October 31, 2012 in conjunction with certain dispositions, to $81.4 million, and on November 30, 2012 to $70 million. The revolving term credit facility and the working capital credit facility have a maturity date of July 10, 2013, and all outstanding advances become repayable on July 10, 2013. Accordingly, at September 30, 2012, the bank loans have been classified as a current liability. Under the agreement, advances 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 3% to 4% depending on the borrowing option used. At September 30, 2012, no amounts were drawn in U.S. funds. The average effective interest rate on advances under the facilities in 2012 was 4.5% (September 30, 2011 - 5.7%). The Company had approximately $0.4 million in letters of credit outstanding at September 30, 2012 that reduce the amount of credit available to the Company.Loans are secured by a floating charge debenture over all assets and guarantees by material subsidiaries. The available lending limits of the facilities are scheduled to be reviewed on or before December 15, 2012 and are based on the bank syndicate's interpretations of the Company's reserves and future commodity prices. There can be no assurance that the amount of the available facilities or the applicable margins will not be adjusted as a result of future dispositions, changes in reserve values, future commodity prices or at the next scheduled review. 6. DECOMMISSIONING OBLIGATIONSSeptember 30, 2012December 31, 2011Balance at January 1$62,848$51,550Provisions incurred9324,878Total abandonment expenditures(392)(249)Provisions disposed(11,143)(1,316)Change in estimates2,7146,355Accretion expense8791,630Ending balance$55,838$62,848The Company's decommissioning obligations result from its ownership interest in oil and natural gas assets including well sites and gathering systems. The Company has estimated the net present value of the decommissioning obligations to be $55.8 million as at September 30, 2012 (December 31, 2011 - $62.8 million) based on an undiscounted inflation-adjusted total future liability of $67.2 million (December 31, 2011 - $80.8 million). These payments are expected to be made over the next 25 years with the majority of costs to be incurred between 2013 and 2030. At September 30, 2012, the liability has been calculated using an inflation rate of 2.0% (December 31, 2011 - 2.0%) and discounted using a risk-free rate of 1.0% to 2.5% (December 31, 2011 - 0.9% to 3.1%) depending on the estimated timing of the future obligation. 7. 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. 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, 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, 2012 and the year ended December 31, 2011 are as follows:September 30, 2012December 31, 2011Number of optionsWeighted average exercise priceNumber of optionsWeighted average exercise priceOutstanding at January 114,014,182$1.6912,006,232$2.32Granted during the period15,0000.574,484,8000.74Exercised during the period--(64,400)0.79Expired during the period(3,380,582)3.72(1,564,150)4.27Forfeited during the period(463,400)0.82(848,300)1.01Ending balance10,185,200$1.0514,014,182$1.69Exercisable, end of period6,480,083$1.186,764,582$2.60The range of exercise prices of the outstanding options is as follows:Range of exercise pricesNumber of optionsWeighted average exercise priceWeighted average remaining life (years)$0.45 to $0.67187,500$0.493.1$0.68 to $1.025,770,3000.743.0$1.03 to $1.543,375,7501.072.9$2.33 to $3.50574,9502.691.0$3.51 to $4.90276,7004.250.9Total at September 30, 201210,185,200$1.052.8The weighted average common share price at the date of exercise for stock options exercised in 2011 was $1.20. Subsequent to September 30, 2012, 5.7 million stock options were issued to staff and 0.7 million options expired or were forfeited to November 12, 2012.The fair value of the options granted in the nine months ended September 30, 2012 and 2011 were estimated using the Black-Scholes model with the following weighted average inputs:September 30, 2012September 30, 2011Fair value at grant date$0.30$0.39Common share price$0.57$0.75Exercise price$0.57$0.75Volatility61%59%Option life5 years5 yearsDividends0%0%Risk-free interest rate1.28%1.67%Forfeiture rate15%15%This estimated forfeiture rate is adjusted to the actual forfeiture rate when each tranche vests. Stock-based compensation cost of $0.5 million (September 30, 2011 - $0.7 million) was expensed during the nine months ended September 30, 2012. Stock-based compensation cost of $0.1 million (September 30, 2011 - $0.2 million) was expensed during the three months ended September 30 2012. In addition, stock-based compensation expense of $0.4 million (September 30, 2011 - $0.5 million) was capitalized during the nine months ended September 30, 2012. For the three months ended September 30, 2012, $0.1 million of stock-based compensation was capitalized (September 30, 2011 - $0.2 million).8. EARNINGS (LOSS) PER SHAREBasic and diluted earnings (loss) per share were calculated as follows:Three months ended September 30Nine months ended September 302012201120122011Earnings (loss) for the period$94$7,472$(22,598)$9,723Weighted average number of common shares (basic) (in thousands of shares)Common shares outstanding at beginning of period172,550172,550172,550172,485Effect of stock options exercised---49Weighted average number of common shares (basic)172,550172,550172,550172,534Effect of dilutive stock options---506Weighted average number of common shares (diluted)172,550172,550172,550173,040Basic and diluted earnings (loss) per share$-$0.04$(0.13)$0.06The 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, 2012, 10,185,200 options (September 30, 2011 - 14,289,032 options) and 59,316,889 common shares reserved for convertible debentures (September 30, 2011 - 59,316,889) were excluded from calculating dilutive earnings as they were anti-dilutive. For the nine months ended September 30, 2012, 10,185,200 options (September 30, 2011 - 11,702,932 options) and 59,316,889 common share reserved for convertible debentures (September 30, 2011 - 59,316,889) were excluded from calculating dilutive earnings as they were anti-dilutive.9. OTHER INCOME (EXPENSES)Other income (expenses) includes the following:Three months ended September 30Nine months ended September 302012201120122011Realized gain (loss) on derivative contracts$1,680$871$3,198$(353)Unrealized gain (loss) on derivative contracts(2,656)6,35034711,166Gain on sale of property, plant and equipment8,0803,4764,0814,622$7,104$10,697$7,626$15,43510. FINANCE INCOME AND EXPENSESThree months ended September 30Nine months ended September 302012201120122011Income:Interest income on cash equivalents$-$-$-$5Other-212449Expenses:Interest and financing costs on bank loans(1,319)(667)(3,603)(2,376)Interest on convertible debentures(1,771)(1,771)(5,314)(3,859)Accretion on convertible debentures(498)(462)(1,451)(972)Accretion on decommissioning obligations(242)(439)(879)(1,295)Other(33)(3)(42)(18)Net finance expenses$(3,863)$(3,321)$(11,265)$(8,466)11. SUPPLEMENTAL CASH FLOW INFORMATIONChanges in non-cash working capital is comprised of:September 30, 2012September 30, 2011Source (use) of cashAccounts receivable and accruals$3,234$4,863Prepaid expenses and deposits330363Accounts payable and accruals(39,470)28,698$(35,906)$33,924Related to operating activities$(692)$483Related to financing activities$(175)$(253)Related to investing activities$(35,039)$33,69412. FINANCIAL RISK MANAGEMENT(a)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.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, 2012:Financial LiabilitiesLess than one yearOne to two yearsTwo to three yearsThree to four yearsFour to five yearsNon-derivative financial liabilitiesAccounts payable and accruals (1)$21,103$-$-$-$-Bank loans - principal (2)88,922----Convertible debentures- Interest (1)5,6267,0857,0855,2103,335- Principal---50,00046,000Total$115,651$7,085$7,085$55,210$49,335(1)Accounts payable and accruals includes $1.5 million of interest relating to convertible debentures. The total cash interest payable in less than one year on the convertible debentures is $7.1 million.(2)Assumes the remaining credit facilities are not renewed on July 10, 2013. (b)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.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. Had the borrowing rate on bank loans been 100 basis points higher (or lower) throughout the nine months ended September 30, 2012, earnings would have been affected by approximately $0.6 million (September 30, 2011 - $0.3 million) based on the average bank debt balance outstanding during the period.Commodity price risk. Commodity price risk is the risk that 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.At September 30, 2012, the Company had fixed price swap contracts for an average of 1,500 barrels per day of crude oil with a remaining term of October to December 2012 at a weighted average NYMEX crude oil price of Canadian $103.87 per barrel. 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, 2012, the Company estimates that it would receive approximately $1.7 million to terminate these contracts (December 31, 2011 - receive $1.4 million). Subsequent to September 30, 2012, the Company settled two derivative contracts, each for 250 barrel per day of oil for November and December of 2012 for $0.4 million.The fair value of derivative contracts at September 30, 2012 would have been impacted as follows had the oil prices used to estimate the fair value changed by:Effect of an increase in price on after-tax earningsEffect of a decrease in price on after-tax earningsCanadian $1.00 per barrel change in the oil prices$104$(104)The Company realized a gain of $0.1 million related to its physical sales contracts to sell 7,000 GJ per day of natural gas for August and September 2012 at an average AECO price of $2.45 per GJ which is included in oil and gas sales. (c) 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 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 $141.8 million, bank loans of $88.9 million, convertible debentures with a face value of $96.0 million and the cash working capital deficiency of $8.1 million, which excludes the current portion of unrealized gains 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 either the annualized current quarter funds from operations or the twelve-month trailing funds from operations (cash flow from operating activities before changes in non-cash working capital and 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. Funds from operations in the quarter, annualized current quarter funds from operations, twelve-month trailing funds from operations and total net debt to funds from operations are not defined by International Financial Reporting Standards and therefore are referred to as non-GAAP measures.September 30, 2012December 31, 2011Bank loans$88,922$88,682Accounts payable and accruals21,10360,573Current assets(1)(13,034)(16,599)Net debt before convertible debentures$96,991$132,656Convertible debentures (liability component)86,24784,796Total net debt$183,238$217,452Cash from operating activities in the quarter$5,845$16,462Decommissioning expenditures in the quarter27146Changes in non-cash working capital in the quarter(147)389Funds from operations in the quarter$5,725$16,997Annualized current quarter funds from operations$22,900$67,988Twelve-month trailing funds from operations$40,944$54,464Net debt before convertible debentures to funds from operations- Annualized current quarter funds from operations4.22.0- Twelve-month trailing funds from operations2.42.4Total net debt to funds from operations- Annualized current quarter funds from operations8.03.2- Twelve-month trailing funds from operations4.54.0(1)Excludes unrealized gains on derivative contracts.There were no changes in the Company's approach to capital management during the three months ended September 30, 2012.The high ratios reflect low natural gas prices and 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, 2011 is the result of a 30 per cent decline in natural gas prices and a 16 per cent decline Canadian oil prices compared to the fourth quarter of 2011. Since September 30, 2012, the Company has applied proceeds on disposition of assets of approximately $18.7 million to reduce bank loans. Also see note 14. 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.13. COMMITMENTS AND CONTINGENCIES(a) Capital commitments. At September 30, 2012, the Company has "farm-in" agreements whereby the Company may earn working interests in oil and gas properties in exchange for undertaking capital spending programs to develop the properties. The Company has farm-in obligations to drill four gross (3.9 net capital) horizontal wells in the Cardium geological formation prior to the end of 2012. One agreement has a $100,000 non-performance fee clause should the Company fail to drill the well. Another agreement pertains to two wells; there is a $35,000 non-performance fee should the Company fail to drill both wells, and if only one well is drilled, the Company would also forfeit fifty per cent of the interest in the first well drilled under the agreement; in a second agreement pertaining to one of these wells, there is also a $25,000 non-performance fee should the Company fail to drill the well. In a third agreement, there is a $200,000 non-performance fee should the Company fail to drill the well. One gross (1 net) well has been drilled subsequent to September 30, 2012. (b) Other commitments and contingencies. At September 30, 2012, the Company had firm service gas transportation agreements in which the Company guarantees that certain minimum volumes of natural gas will be shipped on various gas transportation systems. The terms of the various agreements expire in one to eight years. If no volumes were shipped pursuant to the agreements, the maximum amounts payable under the guarantees based on current tariff rates are as follows: 20122013201420152016ThereafterFirm service commitment$277$1,021$818$697$110$299Firm service committed volumes (MMcfd)15148733Subsequent to September 30, 2012, the Company entered into a new head office lease at a rate of approximately $560,000 per year starting December 1, 2012 and ending on June 30, 2014. There are no material changes to other commitments and contingencies from those disclosed in the Company's annual audited consolidated financial statements as at and for the years ended December 31, 2011 and 2010.14. SUBSEQUENT EVENTSSubsequent to September 30, 2012, the Company sold or has entered into agreements to sell properties considered to be non-strategic assets for cash consideration of approximately $37.5 million (subject to normal course closing adjustments). Proceeds were used or will be used to repay bank loans.Corporate Information Head Office700 Selkirk House555 4th Avenue S.W.Calgary, AlbertaCanada T2P 3E7Head Office (effective November 26, 2012) 2200, 333 7th Avenue S.W.Calgary, AlbertaCanada T2P 2Z1Phone (403) 262-6307Fax (403) 261-2792Website www.andersonenergy.caDirectorsJ.C. Anderson(4) Calgary, AlbertaBrian H. Dau Calgary, AlbertaChristopher L. Fong (1)(2)(3)(4) Calgary, AlbertaGlenn D. Hockley (1)(3)(4) Calgary, AlbertaDavid J. Sandmeyer (2)(3)(4)Calgary, AlbertaDavid G. Scobie (1)(2)(4) Calgary, AlbertaMember of:(1) Audit Committee(2) Compensation & CorporateGovernance Committee(3) Reserves Committee(4) Special Committee AuditorsKPMG LLPIndependent EngineersGLJ Petroleum Consultants Ltd.Legal CounselBennett Jones LLP Registrar & Transfer AgentValiant Trust Company Stock ExchangeThe Toronto Stock Exchange Symbol AXL, AXL.DB, AXL.DB.B OfficersJ.C. AndersonChairman of the BoardBrian H. DauPresident & Chief Executive OfficerDavid M. SpykerChief Operating OfficerM. Darlene WongVice President Finance, Chief Financial Officer & 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 price bbl - barrelbpd - barrels per day BOE - barrels of oil equivalentBOED - barrels of oil equivalent per dayMBOE - thousand barrels of oil equivalentMMBOE - million barrels of oil equivalentGJ - gigajoule Mcf - thousand cubic feetMcfd - thousand cubic feet per dayMMcfd - million cubic feet per dayNGL - natural gas liquidsWTI - West Texas IntermediateNYMEX - The New York Mercantile ExchangeFOR FURTHER INFORMATION PLEASE CONTACT: Contact Information: Anderson Energy Ltd.Brian H. DauPresident & Chief Executive Officer(403) 262-6307info@andersonenergy.ca