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Press release from Marketwire

Anderson Energy Announces 2012 Second Quarter Results

Monday, August 13, 2012

Anderson Energy Announces 2012 Second Quarter Results09:00 EDT Monday, August 13, 2012CALGARY, ALBERTA--(Marketwire - Aug. 13, 2012) - Anderson Energy Ltd. ("Anderson" or the "Company") (TSX:AXL) is pleased to announce its operating and financial results for the three and six months ended June 30, 2012.HIGHLIGHTSFunds from operations in the second quarter of 2012 were $7.6 million. Production in the second quarter of 2012 was 6,825 BOED. Funds from operations for the first half of 2012 were $18.2 million. The operating netback per BOE in the second quarter of 2012 was $21.04 per BOE compared to $25.47 per BOE in the second 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. Cardium oil netbacks averaged approximately $46.54 per BOE in the second quarter of 2012. Oil and NGL production averaged 2,419 bpd in the second quarter of 2012 consistent with the same period in 2011. Oil represented 1,669 bpd of total production. Oil and NGL revenue represented 79% of Anderson's total oil and gas sales in the second quarter of 2012 compared to 65% in the same period of 2011. Subsequent to June 30, 2012, the Company has sold or agreed to sell approximately 428 BOED of production (51% natural gas) for cash consideration of $30.9 million subject to normal post closing adjustments. Approximately $30.5 million of these dispositions have now closed and the remainder is subject to normal course rights of first refusal. The Company has additional non-strategic assets which it is currently marketing to improve its financial flexibility. The Company's lenders have re-determined the Company's bank lines to initially be $125 million, stepping down as dispositions close to $100 million and ultimately to $90 million on September 30, 2012. 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") has initiated a process to identify, examine and consider a range of strategic alternatives with a view to enhancing shareholder value. This process is ongoing. Anderson has engaged BMO Capital Markets and RBC Capital Markets as financial advisors to assist in this process. FINANCIAL AND OPERATING HIGHLIGHTSThree months ended June 30Six months ended June 30(thousands of dollars, unless otherwise stated)20122011% Change20122011% ChangeOil and gas sales*$20,311$31,566(36%)$45,519$57,152(20%)Revenue, net of royalties*$18,290$27,776(34%)$40,735$51,059(20%)Funds from operations$7,606$13,944(45%)$18,222$24,812(27%)Funds from operations per shareBasic and diluted$0.04$0.08(50%)$0.11$0.14(21%)Earnings (loss) before effect of impairments$(1,828)$5,932(131%)$(7,692)$2,251(442%)Earnings (loss) per share before effect of impairments, basic and diluted$(0.01)$0.03(133%)$(0.04)$0.01(500%)Earnings (loss)$(16,828)$5,932(384%)$(22,692)$2,251(1108%)Earnings (loss) per shareBasic and diluted$(0.10)$0.03(433%)$(0.13)$0.01(1400%)Capital expenditures, net of proceeds on dispositions$4,786$26,284(82%)$16,876$68,638(75%)Bank loans plus cash working capital deficiency$131,675$71,46484%Convertible debentures$85,749$83,8722%Shareholders' equity$141,427$187,401(25%)Average shares outstanding (thousands)Basic172,550172,548-172,550172,526-Diluted172,550172,935-172,550173,163-Ending shares outstanding (thousands)172,550172,550-Average daily sales:Natural gas (Mcfd)26,43831,990(17%)26,95132,955(18%)Oil (bpd)1,6691,759(5%)1,8121,56716%NGL (bpd)75066712%7276836%Barrels of oil equivalent (BOED)6,8257,758(12%)7,0317,742(9%)Average prices:Natural gas ($/Mcf)$1.72$3.79(55%)$1.87$3.68(49%)Oil ($/bbl)$81.58$99.39(18%)$85.31$93.00(8%)NGL ($/bbl)$54.38$74.24(27%)$60.66$70.03(13%)Barrels of oil equivalent ($/BOE)*$32.70$44.71(27%)$35.57$40.78(13%)Realized gain (loss) on derivative contracts ($/BOE)$2.10$(1.17)279%$1.19$(0.87)237%Royalties ($/BOE)$3.25$5.37(39%)$3.74$4.35(14%)Operating costs ($/BOE)$10.06$12.04(16%)$10.34$11.34(9%)Transportation costs ($/BOE)$0.45$0.66(32%)$0.31$0.50(38%)Operating netback ($/BOE)$21.04$25.47(17%)$22.37$23.72(6%)Wells drilled (gross)-5(100%)320(85%)* 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 were $4.8 million in the second quarter of 2012. This compares to capital expenditures of $26.3 million (net of proceeds on dispositions of $0.2 million) in the second quarter of 2011. Anderson's funds from operations were $7.6 million in the second quarter of 2012 compared to $13.9 million in the second quarter of 2011. Oil and gas sales were lower due to lower prices and lower production in the quarter. This was partially offset by an improvement in operating costs in the second quarter to $10.06 per BOE compared to $12.04 per BOE in the same period in 2011. This improvement primarily results from the Company's 2011 investments in low operating cost crude oil infrastructure. During the second quarter of 2012, oil and NGL sales represented 79% of Anderson's total oil and gas sales compared to 65% in the second quarter of 2011. The Company has 1,500 barrels per day of fixed price oil swaps for the remainder of 2012. The Company's unrealized gain on its oil derivatives was $4.7 million for the second quarter of 2012. The Company's operating netback was $21.04 per BOE in the second quarter of 2012 compared to $25.47 per BOE in the second quarter of 2011. Anderson's netback for its Cardium horizontal properties in the second quarter of 2012 was approximately $46.54 per BOE (exclusive of hedging). Average wellhead natural gas price ($/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 20121.7273.1532.7021.0412.25The Company recorded a loss of $16.8 million in the second quarter of 2012 primarily due to the impairment of natural gas assets as a result of low natural gas prices. Subsequent to June 30, 2012, Anderson sold or has agreed to sell oil and gas properties for cash consideration of $30.9 million. Pro forma the dispositions, outstanding bank loans would be $88.8 million at June 30, 2012. COMMODITY PRICES The Company's average crude oil and natural gas liquids sales prices in the second quarter of 2012 were $81.58 and $54.38 per barrel respectively compared to $99.39 and $74.24 per barrel in the second quarter of 2011. Light, sweet oil differentials between Cushing, Oklahoma and Edmonton, Alberta were an average $10.25 per bbl U.S. discount in the second quarter of 2012, compared to an average $1.46 per bbl U.S. premium as recently as the fourth quarter of 2011 (a difference in the discount of $11.71 per bbl U.S.). In the third quarter of 2012, light sweet, oil differentials are expected to be less than in the second quarter of 2012; however, they will remain volatile in the near term depending on refining demand. The Company's average natural gas sales price was $1.72 per Mcf in the second quarter of 2012 compared to $3.79 per Mcf in the second quarter of 2011. AECO natural gas prices in April 2012 reached lows not seen in western Canada since 1996. Natural gas pricing has been progressively recovering since that point.COMMODITY HEDGING CONTRACTSCrude Oil. As part of its price management strategy, the Company has fixed price swap contracts based on the NYMEX crude oil price in Canadian dollars. As of August 10, 2012, the average volumes and prices for these contracts are summarized below:PeriodWeighted average volume (bpd)Weighted average WTI Canadian ($/bbl)July to December 20121,500103.87By comparison, WTI Canadian averaged $103.04 per bbl in the first quarter of 2012, $94.29 per bbl in the second quarter of 2012 and $89.17 per bbl in July 2012. Subsequent to June 30, 2012, the Company entered into 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. 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 second quarter of 2012 was 6,825 BOED. Oil and natural gas liquids production averaged 2,419 bpd. Overall production was lower in the second 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 730 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 3.8 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 *Garrington11284Willesden Green7757Ferrier3420Pembina4119Total Cardium inventory264180Horizontal prospect inventory in other zones9150Total Cardium and other zone horizontal inventory355230Oil wells drilled to August 10, 20127556Remaining Cardium and other zone inventory, August 10, 2012280174* Net is net revenue interest The net prospect inventory has been slightly reduced since the first quarter of 2012 due to non-core dispositions, the majority of which are non-operated. 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. 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. In addition, a liquids handling debottlenecking project at the Westpem 14-03-050-14 W5 compressor station has reduced the backpressure on the field resulting in incremental gas production of 350 Mcfd. 2012 CAPITAL PROGRAM Anderson intends to commence with a one rig drilling program dedicated exclusively to its Cardium horizontal drilling program in the second half of 2012. Planning and surface land acquisition for this program is complete. The extent of the program is dependent on the continued success of the Company's non-strategic property disposition program and available bank lines. PROPERTY DISPOSITIONS Since June 30, 2012, Anderson has sold or agreed to sell approximately 428 BOED of production (51% natural gas) for cash consideration of $30.9 million subject to normal post closing adjustments. Two outside operated units (Cardium oil unit and Pekisko gas unit), one half section of operated fully developed Cardium lands and some additional minor properties were sold in this process. The Cardium production was sold at $102,000 per BOED based on first quarter 2012 production estimates and represented 6.3% of the Company's Cardium production. Since January 1, 2012, the Company has sold or agreed to sell interests in 13 properties for total consideration of $37 million. Total production sold or agreed to be 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. 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 gas-weighted assets which it is currently marketing to improve its financial flexibility. 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. As previously reported by the Company on July 6, 2012, the Company's bank lines have been re-determined to be $90 million on September 30, 2012. The lower bank lines are attributable to dramatic reductions in lender natural gas price decks and to the sale of assets to date, including those completed subsequent to the end of the quarter. 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. 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 United States summer resulting in higher electrical generation demand. Natural gas storage is still higher than average for this time of year and, as a result, shoulder season pricing could soften. Normal winter temperatures in 2012/2013 could support natural gas prices at levels more consistent with the full cycle replacement costs of the commodity. 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, to protect the balance sheet, both oil and gas hedging opportunities are continuously evaluated. STRATEGIC ALTERNATIVES As previously announced, the Board of Directors has initiated 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. 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.Brian H. DauPresident & Chief Executive Officer August 13, 2012Management's Discussion and Analysis FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2012 AND 2011The following management's discussion and analysis ("MD&A") is dated August 10, 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 six months ended June 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. Funds from operations were $7.6 million for the second quarter of 2012 which were lower than the second quarter of 2011 (45% decrease) as a result of the substantial drop in natural gas prices (55% decrease) and lower natural gas production (17% decrease). Oil prices decreased 18% in the second quarter of 2012 compared to the second quarter of 2011 and oil production decreased 5% compared to 2011. The Company did not drill any new wells in the second quarter. Historically, the second quarter is not an active drilling quarter. Funds from operations for the second quarter of 2012 were $3.0 million lower than the first quarter of 2012 due to declining natural gas prices (14% decrease), lower oil prices (8% decrease) and reduced production volumes (6% decrease) due to natural production declines and non-core property dispositions.Revenue and Production. Oil and natural gas liquids, which have higher sales prices and netbacks than natural gas, have taken a larger role in the Company's sales mix. Oil and natural gas liquids represented 79% of oil and gas sales in the second quarter of 2012, consistent with the first quarter of 2012 and up 14% from the second quarter of 2011. For the six months ended June 30, 2012, oil and natural gas liquids represented 79% of oil and gas sales compared to 61% in the comparable period in 2011. Oil sales for the second quarter of 2012 averaged 1,669 bpd compared to 1,956 bpd in the first quarter of 2012 and 1,759 bpd for the second quarter of 2011. The decrease in volumes from the first quarter of 2012 is due to natural production declines as no new wells were drilled in the second quarter of 2012. For the first half of 2012, oil sales averaged 1,812 bpd compared to 1,567 bpd in the first half of 2011. Higher oil production in 2012 versus 2011 is due to a focus over the last couple of years on Cardium oil development exclusively. 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 730 Mcfd of natural gas production with high operating costs and has sold some non-core assets. Gas sales volumes continued to decline in the second quarter of 2012 to 26.4 MMcfd from 27.5 MMcfd in the first quarter of 2012. Gas sales volumes for the six months ended June 30, 2012 were 27.0 MMcfd compared to 33.0 MMcfd for the same period of 2011. Natural gas liquids sales for the three months ended June 30, 2012 averaged 750 bpd compared to 703 bpd in the first quarter of 2012 and 667 bpd for the second quarter of 2011. For the six months ended June 30, 2012, natural gas liquids sales averaged 727 bpd compared to 683 bpd in the first half of 2011. The following tables outline production revenue, volumes and average sales prices for the three and six month periods ended June 30, 2012 and 2011. OIL AND NATURAL GAS SALESThree months ended June 30Six months ended June 30(thousands of dollars)2012201120122011Natural gas$4,130$11,034$9,162$21,954Oil(1)12,39015,91228,13626,375NGL3,7114,5058,0218,654Royalty and other80115200169Total oil and gas sales(1)$20,311$31,566$45,519$57,152(1)The three months ended June 30, 2012 excludes the realized gain (loss) and unrealized gain on derivative contracts of $1.3 million and $4.7 million respectively (June 30, 2011 - $(0.8) million and $7.7 million respectively). The six months ended June 30, 2012 excludes the realized gain (loss) and unrealized gain on derivative contracts of $1.5 million and $3.0 million respectively (June 30, 2011 - $(1.2) million and $4.8 million respectively). PRODUCTIONThree months ended June 30Six months ended June 302012201120122011Natural gas (Mcfd)26,43831,99026,95132,955Oil (bpd)1,6691,7591,8121,567NGL (bpd)750667727683Total (BOED)6,8257,7587,0317,742PRICESThree months ended June 30Six months ended June 302012201120122011Natural gas ($/Mcf)$1.72$3.79$1.87$3.68Oil ($/bbl)(1)81.5899.3985.3193.00NGL ($/bbl)54.3874.2460.6670.03Total ($/BOE)(1)(2)$32.70$44.71$35.57$40.78(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. These differentials widened dramatically in the first quarter of 2012, decreasing the oil price realized by the Company. In the second quarter of 2012, average differentials were approximately $10.25 per bbl U.S. which was similar to the first quarter. Differentials peaked in March and April but narrowed significantly by the end of the second quarter, and may remain volatile at least in the near-term. 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 in the first half 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 June 30, 2012, the above noted oil prices do not include a realized gain on derivative contracts of $1.3 million (June 30, 2011 - $0.8 million loss). The realized oil price including this gain was $90.18 per barrel for the second quarter of 2012 compared to $94.25 per barrel for the second quarter of 2011. For the six months ended June 30, 2012, the above noted oil prices do not include a realized gain on derivative contracts of $1.5 million (June 30, 2011 - $1.2 million loss). The realized oil price including this gain was $89.91 per barrel for the first half of 2012 compared to $88.68 per barrel for the first half of 2011. The Company's average natural gas sales price was $1.72 per Mcf for the three months ended June 30, 2012, 14% lower than the first quarter of 2012 price of $2.01 per Mcf and 55% lower than the second quarter of 2011 price of $3.79 per Mcf. For the six months ended June 30, 2012, the Company's average natural gas sales price was $1.87 per Mcf compared to $3.68 per Mcf for the first half of 2011.Commodity Contracts. At June 30, 2012, the following derivative contracts were outstanding and recorded at estimated fair value:PeriodWeighted average volume (bpd)Weighted average WTI Canadian ($/bbl)July 1, 2012 to December 31, 20121,500103.87By comparison, WTI Canadian averaged $103.04 per bbl in the first quarter of 2012, $94.29 per bbl in the second quarter of 2012 and $89.17 per bbl in July 2012.Derivative contracts had the following impact on the consolidated statements of operations and comprehensive loss for the three and six months ended June 30, 2012 and 2011:Three months ended June 30Six months ended June 30(thousands of dollars)2012201120122011Realized gain (loss) on derivative contracts$1,305$(824)$1,518$(1,224)Unrealized gain on derivative contracts4,6927,6653,0034,816$5,997$6,841$4,521$3,592Subsequent to June 30, 2012, the Company entered into physical sales contracts to sell 7,000 GJs per day of natural gas for August and September 2012 at an average AECO price of $2.45 per GJ. Royalties. For the second quarter of 2012, the average royalty rate was 10.0% of oil and gas sales compared to 11.0% in the first quarter of 2012 and 12.0% in the second quarter of 2011. For the first half of 2012, the average royalty rate was 10.5% of revenue compared to 10.7% in the first half of 2011. Royalty rates quarter over quarter have declined slightly as a result of lower commodity prices. Royalties as a percentage of total oil and gas sales are highly sensitive to prices and adjustments to gas cost allowance and so royalty rates can fluctuate from quarter to quarter.Three months ended June 30Six months ended June 302012201120122011Gross Crown royalties9.2%8.8%8.7%9.3%Gas cost allowance(4.3%)(3.8%)(4.3%)(5.2%)Other royalties5.1%7.0%6.1%6.6%Total royalties10.0%12.0%10.5%10.7%Royalties ($/BOE)$3.25$5.37$3.74$4.35Operating Expenses. Operating expenses were $10.06 per BOE for the three months ended June 30, 2012 compared to $10.61 per BOE in the first quarter of 2012 and $12.04 per BOE in the second quarter of 2011. Operating expenses were $10.34 per BOE for the six months ended June 30, 2012 compared to $11.34 per BOE in same period in 2011. The decrease in operating expenses for the three and six months ended June 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. Transportation Expenses. For the three months ended June 30, 2012, transportation expenses were $0.45 per BOE compared $0.66 per BOE in the second quarter of 2011. For the six months ended June 30, 2012, transportation expenses were $0.31 per BOE compared to $0.50 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 June 30Six months ended June 30(thousands of dollars)2012201120122011Revenue (1)$20,311$31,566$45,519$57,152Realized gain (loss) on derivative contracts1,305(824)1,518(1,224)Royalties(2,021)(3,790)(4,784)(6,093)Operating expenses(6,250)(8,493)(13,238)(15,883)Transportation expenses(279)(469)(390)(702)Operating netback$13,066$17,990$28,625$33,250Sales (MBOE)621.1706.01,279.61,401.3Per BOERevenue (1)$32.70$44.71$35.57$40.78Realized gain (loss) on derivative contracts2.10(1.17)1.19(0.87)Royalties(3.25)(5.37)(3.74)(4.35)Operating expenses(10.06)(12.04)(10.34)(11.34)Transportation expenses(0.45)(0.66)(0.31)(0.50)Operating netback per BOE$21.04$25.47$22.37$23.72(1)Includes royalty and other income classified with oil and gas sales. The three months ended June 30, 2012 excludes the unrealized gain on derivative contracts of $4.7 million (June 30, 2011 - $7.7 million). The six months ended June 30, 2012 excludes the unrealized gain on derivative contracts of $3.0 million (June 30, 2011 - $4.8 million).Depletion and Depreciation. Depletion and depreciation was $12.3 million ($19.77 per BOE) for the second quarter of 2012 compared to $13.0 million ($19.81 per BOE) in the first quarter of 2012 and $13.3 million ($18.90 per BOE) in the second quarter of 2011. Depletion and depreciation expense for the second quarter of 2012 is lower compared to the same period of 2011 due to lower overall production volumes, whereas the depletion and depreciation rate per BOE is higher in 2012 due to the higher capital costs associated with the 2011 and 2012 capital programs. Impairment Loss. In the second quarter of 2012, declines in forecasted natural gas commodity prices and the ongoing strategic alternatives process are indicators of impairment for certain cash generating units ("CGUs"). Forecasted natural gas commodity prices at June 30, 2012 declined between eight and 18 per cent when compared to December 31, 2011. The following table shows the differences in the future natural gas commodity prices used by the Company's independent qualified reserves evaluators at June 30, 2012 compared to December 31, 2011:AECO Gas Price ($Cdn/MMBTU)YearJune 30, 2012December 31, 2011Difference20133.444.13(0.69)20143.904.59(0.69)20154.365.05(0.69)20164.825.51(0.69)20175.285.97(0.69)20185.686.21(0.53)20195.806.33(0.53)20205.916.46(0.55)20216.036.58(0.55)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. Management's estimated reserves values used in the evaluation of recoverable amounts of certain CGUs were calculated using a discount rate of 10 per cent. At June 30, 2012, if the discount rate used had been two percent higher or two percent lower, the reserves values estimated would have been approximately $11 million lower or $13 million higher respectively. General and Administrative Expenses. General and administrative expenses excluding stock-based compensation were $2.4 million ($3.94 per BOE) for the second quarter of 2012 compared to $2.1 million ($3.26 per BOE) in the first quarter of 2012 and $2.0 million ($2.86 per BOE) for the second quarter of 2011. For the six months ended June 30, 2012, general and administrative expenses excluding stock-based compensation were $4.6 million ($3.59 per BOE) compared to $4.7 million ($3.32 per BOE) for the same period in 2011. The increase in cash general and administrative expenses is the result of reduced overhead recoveries from limited capital spending in the second quarter of 2012 compared to same period in 2011.Three months ended June 30Six months ended June 30(thousands of dollars)2012201120122011General and administrative (gross)$3,539$3,566$6,958$7,693Overhead recoveries(243)(457)(708)(810)Capitalized(851)(1,092)(1,659)(2,224)General and administrative (cash)$2,445$2,017$4,591$4,659Net stock-based compensation203257430491General and administrative$2,648$2,274$5,021$5,150General and administrative (cash) ($/BOE)$3.94$2.86$3.59$3.32% Capitalized24%31%24%29%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 $0.3 million in the second quarter of 2012 ($0.2 million net of amounts capitalized) compared to $0.4 million for the second quarter of 2011 ($0.3 million net of amounts capitalized). For the six months ended June 30, 2012, stock-based compensation costs were $0.7 million ($0.4 million net of amounts capitalized) compared to $0.8 million ($0.5 million net of amounts capitalized) in the same period of 2011.Finance Expenses. Finance expenses were $3.8 million in the second quarter of 2012, compared to $3.6 million for the first quarter of 2012 and $2.8 million in the second quarter of 2011. For the six months ended June 30, 2012, finance expenses were $7.4 million compared to $5.2 million in the same period of 2011. While the average effective interest rate on outstanding bank loans was 4.2% for the six months ended June 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 June 30Six months ended June 30(thousands of dollars)2012201120122011Interest and accretion on convertible debentures$2,252$1,441$4,496$2,598Interest expense on credit facilities and other1,2518892,2931,724Accretion on decommissioning obligations319439637856Finance expenses$3,822$2,769$7,426$5,178Decommissioning Obligations. In the second quarter of 2012, the Company recorded $0.3 million relating to current activity and changes in estimates. Accretion expense was $0.3 million for the second quarter of 2012 compared to $0.4 million in the second quarter of 2011 and was included in finance expenses. The Company also disposed of $0.6 million of decommissioning obligations in the second quarter of 2012. The risk-free discount rates used by the Company to measure the obligations at June 30, 2012 were between 0.9% and 3.1% depending on the timelines to reclamation. Income Taxes. Anderson is not currently taxable. The Company estimates that it has approximately $495 million in tax pools at June 30, 2012. Funds from Operations. Funds from operations for the second quarter of 2012 were $7.6 million ($0.04 per share), down 28% from the $10.6 million ($0.06 per share) recorded in the first quarter of 2012 and down 45% from the $13.9 million ($0.08 per share) recorded in the second quarter of 2011. The decrease in funds from operations in the second quarter of 2012 compared to the first quarter of 2012 was largely due to the continued declines in natural gas prices along with lower oil prices and lower production volumes. Funds from operations for the six months ended June 30, 2012 decreased compared to 2011 for similar reasons.Three months ended June 30Six months ended June 30(thousands of dollars)2012201120122011Cash from operating activities$7,712$14,953$17,018$25,954Changes in non-cash working capital(164)(1,025)839(1,184)Decommissioning expenditures581636542Funds from operations$7,606$13,944$18,222$24,812Earnings. The Company reported a loss of $16.8 million in the second quarter of 2012 compared to a loss of $5.9 million for the first quarter of 2012 and earnings of $5.9 million for the second quarter of 2011. In the second quarter of 2012, earnings were impacted by an impairment loss. 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 The Company spent $4.8 million on capital expenditures, net of proceeds from dispositions in the second quarter of 2012. The breakdown of expenditures is shown below:Three months ended June 30Six months ended June 30(thousands of dollars)2012201120122011Land, geological and geophysical costs$195$3,479$360$3,766Proceeds on disposition-(167)(6,199)(5,367)Drilling, completion and recompletion1,81512,66214,08851,560Drilling incentive credits-(291)-(138)Facilities and well equipment1,9919,4837,12716,565Capitalized general and administrative expenses8511,0921,6592,224Total finding, development & acquisition expenditures4,85226,25817,03568,610Change in compressor and other inventory and equipment(85)-(185)-Office equipment and furniture19262628Total net cash capital expenditures4,78626,284$16,876$68,638Drilling statistics are shown below:Three months ended June 30Six months ended June 302012201120122011GrossNetGrossNetGrossNetGrossNetGas--------Oil--52.932.52016.2Dry--------Total--52.932.52016.2Success rate (%)--100%100%100%100%100%100%Subsequent to June 30, 2012, Anderson entered into agreements to sell or closed the sale of approximately 428 BOED of production (51% natural gas) for cash consideration of $30.9 million (subject to normal course closing adjustments).SHARE INFORMATION The Company's shares have been listed on the Toronto Stock Exchange since September 7, 2005 under the symbol "AXL". As of August 10, 2012, there were 172.5 million common shares outstanding, 11.4 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. During the second quarter of 2011, 4,400 common shares were issued under the employee stock option plan. There were no common shares issued under the employee stock option plan in 2012.Three months ended June 30Six months ended June 302012201120122011High$0.58$1.23$0.68$1.36Low$0.25$0.77$0.25$0.77Close$0.34$0.80$0.34$0.80Volume8,589,54223,392,24724,840,82284,968,086Shares outstanding at June 30172,549,701172,549,701172,549,701172,549,701Market capitalization at June 30$58,666,898$138,039,761$58,666,898$138,039,761The 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 six months ended June 30, 2012 approximately 2.4 million and 10.6 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 second quarter of 2012 (June 30, 2011 - 0.7 million), representing a quarterly turnover ratio of 6% (June 30, 2011 - 26%). LIQUIDITY AND CAPITAL RESOURCES At June 30, 2012, the Company had outstanding bank loans of $119.7 million, convertible debentures of $96.0 million (principal) and a cash working capital deficiency (excluding unrealized gain on derivative contracts) of $12.0 million. The following table shows the changes in bank loans plus cash working capital deficiency: Three months ended June 30Six months ended June 30(thousands of dollars)2012201120122011Bank loans plus cash working capital deficiency, beginning of period$(134,437)$(102,971)$(132,656)$(71,507)Funds from operations7,60613,94418,22224,812Net cash capital expenditures(4,786)(26,284)(16,876)(68,638)Proceeds from issue of convertible debentures, net of issue costs-43,860-43,860Proceeds from exercise of stock options-3-51Decommissioning expenditures(58)(16)(365)(42)Bank loans plus cash working capital deficiency, end of period$(131,675)$(71,464)$(131,675)$(71,464)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 is actively pursuing the sale of its non-strategic assets. The extent of the capital program in the fourth quarter will be dependent on the continued success of this property disposition program, oil and natural gas prices and available credit facilities. Subsequent to June 30, 2012, Anderson sold or agreed to sell oil and gas properties for cash consideration of $30.9 million. Pro forma the dispositions, bank loans would be $88.8 million and bank loan plus working capital deficiency would be $100.8 million at June 30, 2012. At June 30, 2012, the Company had total credit facilities of $135 million, consisting of a $110 million extendible revolving term credit facility, a $10 million working capital credit facility and a $15 million supplemental credit facility with a syndicate of Canadian banks. At June 30, 2012, there were no amounts drawn on the supplemental facility which expired on July 11, 2012. Subsequent to June 30, 2012, the Company's lenders amended and extended the Company's revolving credit facility and working capital credit facility to July 10, 2013. Total bank facilities were initially set at $125 million stepping down as certain dispositions closed subsequent to June 30, 2012, to $100 million on July 31, 2012 and to $90 million on September 30, 2012. 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. The bank lines will consist of a $10 million working capital facility and an $80 million revolving commitment as of September 30, 2012. Under the new 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. The reduction in credit facilities is attributable to dramatic reductions in lender natural gas price decks and to the sale of assets to date, including those completed subsequent to the end of the quarter. 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 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. At June 30, 2012, these obligations include:Loan agreements - Under the renewed credit facility agreement, the reserves-based, revolving term credit facility and working capital credit facility have a term ending on July 10, 2013. If not extended, the facilities cease to revolve and all outstanding advances become repayable on July 10, 2013. Letters of credit - Letters of credit of approximately $0.4 million had been issued in the normal course of business as at June 30, 2012. Convertible debentures - The Company has $96.0 million (principal) in convertible debentures outstanding at June 30, 2012, of which $50.0 million bears interest at 7.5% ("Series A Convertible Debentures") and $46.0 million bears interest at 7.25% ("Series B Convertible Debentures"). Each convertible debenture has a face value of $1,000 with interest payable semi-annually. The Series A Convertible Debentures mature on January 31, 2016 with interest payable on the last day of July and January, commencing July 31, 2011. These convertible debentures are convertible at the holder's option at a conversion price of $1.55 per common share, subject to adjustment in certain events and are not redeemable by the Company before January 31, 2014. The Series B Convertible Debentures mature on June 30, 2017 with interest payable on the last day of June and December, commencing December 31, 2011. These convertible debentures are convertible at the holder's option at a conversion price of $1.70 per common share, subject to adjustment in certain events and are not redeemable by the Company before June 30, 2014. 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 six gross (4.5 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 $100,000 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 third agreement, there is a $200,000 non-performance fee should the Company fail to drill the well. Edmonton Sands Well Program (Natural Gas) - In 2009, the Company committed to a 200 well drilling and completion program in the Edmonton Sands geological formation (the "Program") under a farm-in agreement with a large international oil and gas company (the "Farmor") from which the Company will earn an interest in up to 120 sections of land. The Company is obligated to complete the Program or before March 31, 2013 and has an option to continue the farm-in transaction until March 31, 2014 by committing to drill a minimum of 100 additional wells under similar terms as in the commitment phase to earn a minimum of 50 sections of land. Following the commitment and/or option phases, the Company and the Farmor can then jointly develop the lands on denser drilling spacing under terms of an operating agreement. As of June 30, 2012, the Company had drilled 126 wells under the farm-in agreement and deferred the drilling of the remaining 74 gross wells until 2013 due to depressed natural gas prices. A $550,000 penalty is payable for each well not drilled under the commitment as of March 31, 2013, subject to certain reductions due to unavoidable events beyond the Company's control and rights of first refusal. The Company estimates that its minimum commitment to drill the remaining 74 wells is approximately $10 million. 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 355 gross (230 net revenue) drill-ready Cardium and other horizontal zone oil locations, of which 75 gross (56 net revenue) have been drilled to August 10, 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. Crude oil pricing remains strong, but volatile and Anderson has hedged oil prices to help protect its capital program and its shareholders from volatile oil markets. In response to low natural gas prices, the Company has approximately 730 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. Anderson has substantially grown its Cardium drilling inventory since the beginning of the year and with the completion of the infrastructure projects, newly drilled Cardium horizontal wells can be easily connected to these gathering systems. Unlike natural gas markets, oil prices continue to remain strong and the economics of the Cardium oil drilling programs are excellent. 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") has initiated 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 13 properties for total consideration of $37 million. Total production sold or agreed to be 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. 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. 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 second quarter of 2012 were affected by lower natural gas prices, larger differentials between WTI and Alberta oil prices and lower production volumes. SELECTED QUARTERLY INFORMATION ($ amounts in thousands, except per share amounts and prices)Q2 2012Q1 2012Q4 2011Q3 2011Revenue, net of royalties$18,290$22,445$28,457$24,970Funds from operations$7,606$10,616$16,997$12,655Funds from operations per share, basic and diluted$0.04$0.06$0.10$0.07Earnings (loss) before effect of impairments or reversals thereof$(1,828)$(5,864)$ (4,939)$6,667Earnings (loss) per share before effect of impairments or reversals thereof, basic and diluted$(0.01)$(0.03)$(0.03)$0.04Earnings (loss)$(16,828)$(5,864)$(32,167)$7,472Earnings (loss) per share, basic and diluted$(0.10)$(0.03)$(0.19)$0.04Capital expenditures, including acquisitions net of proceeds on dispositions$4,786$12,090$40,924$49,713Cash from operating activities$7,712$9,306$16,462$11,893Daily salesNatural gas (Mcfd)26,43827,46330,57630,038Oil (bpd)1,6691,9562,1221,709NGL (bpd)750703715636BOE (BOED)6,8257,2367,9337,351Average pricesNatural gas ($/Mcf)$1.72$2.01$3.20$3.85Oil ($/bbl)(2)$81.58$88.48$96.33$89.05NGL ($/bbl)$54.38$67.36$72.71$66.07BOE ($/BOE)(1)(2)$32.70$38.28$44.70$42.16Q2 2011Q1 2011Q4 2010Q3 2010Revenue, net of royalties$27,776$23,283$21,690$17,263Funds from operations$13,944$10,868$9,282$7,876Funds from operations per share, basic and diluted$0.08$0.06$0.05$0.05Earnings (loss) before effect of impairments$5,932$(3,681)$(4,864)$(3,057)Earnings (loss) per share before effect of impairments, basic and diluted$0.03$(0.02)$(0.03)$(0.02)Earnings (loss)$5,932$(3,681)$(36,545)$(39,029)Earnings (loss) per share, basic and diluted$0.03$(0.02)$(0.21)$(0.23)Capital expenditures, including acquisitions net of proceeds on dispositions$26,284$42,354$26,240$39,378Cash from operating activities$14,953$11,001$10,488$8,287Daily salesNatural gas (Mcfd)31,99033,93138,47935,778Oil (bpd)1,7591,372992568NGL (bpd)667699823761BOE (BOED)7,7587,7268,2287,292Average pricesNatural gas ($/Mcf)$3.79$3.58$3.48$3.43Oil ($/bbl)(2)$99.39$84.71$77.62$68.24NGL ($/bbl)$74.24$65.97$58.87$51.41BOE ($/BOE)(1)(2)$44.71$36.80$31.63$28.21(1)Includes royalty and other income classified with oil and gas sales. (2)Excludes realized and unrealized gains (losses) on derivative contracts as follows: 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; 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)June 30, 2012December 31, 2011ASSETSCurrent assets:Cash$-$1Accounts receivable and accruals11,76314,272Prepaid expenses and deposits1,4332,326Unrealized gain on derivative contracts (note 12)4,3871,38417,58317,983Deferred tax asset42,80935,389Property, plant and equipment (notes 3, 4)370,796406,947$431,188$460,319LIABILITIES AND SHAREHOLDERS' EQUITYCurrent liabilities:Accounts payable and accruals$25,185$60,573Bank loans (note 5)119,68688,682Convertible debentures85,74984,796Decommissioning obligations (note 6)59,14162,848289,761296,899Shareholders' equity:Share capital (note 7)171,460171,460Equity component of convertible debentures5,0195,019Contributed surplus10,0849,385Deficit (note 7)(45,136)(22,444)141,427163,420Future operations (note 1)Subsequent events (notes 5, 12, 14)Commitments and contingencies (note 13)$431,188$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 June 30Six months ended June 302012201120122011Oil and gas sales$20,311$31,566$45,519$57,152Royalties(2,021)(3,790)(4,784)(6,093)Revenue, net of royalties18,29027,77640,73551,059Other income (expenses) (note 9)4,6087,6025224,73822,89835,37841,25755,797Operating expenses6,2508,49313,23815,883Transportation expenses279469390702Depletion and depreciation12,27613,34125,31825,696Impairment loss (note 4)20,000-20,000-General and administrative expenses2,6482,2745,0215,150Earnings (loss) from operating activities(18,555)10,801(22,710)8,366Finance income (note 10)8102433Finance expenses (note 10)(3,822)(2,769)(7,426)(5,178)Net finance expenses(3,814)(2,759)(7,402)(5,145)Earnings (loss) before taxes(22,369)8,042(30,112)3,221Deferred income tax expense (benefit)(5,541)2,110(7,420)970Earnings (loss) and comprehensive income (loss) for the period(16,828)5,932(22,692)2,251Basic and diluted earnings (loss) per share (note 8)$(0.10)$0.03$(0.13)$0.01See accompanying notes to the condensed interim consolidated financial statements.ANDERSON ENERGY LTD.Consolidated Statements of Changes in Shareholders' EquitySIX MONTHS ENDED JUNE 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---777-777Options exercised64,40078-(27)-51Earnings for the period----2,2512,251Balance at June 30, 2011172,549,701$171,460$5,019$8,671$2,251$187,401Balance at January 1, 2012172,549,701$171,460$5,019$9,385$(22,444)$163,420Share-based payments---699-699Loss for the period----(22,692)(22,692)Balance at June 30, 2012172,549,701$171,460$5,019$10,084$(45,136)$141,427See accompanying notes to the condensed interim consolidated financial statements.ANDERSON ENERGY LTD.Consolidated Statements of Cash FlowsSIX MONTHS ENDED JUNE 30, 2012 AND 2011(Stated in thousands of dollars)(Unaudited)20122011CASH PROVIDED BY (USED IN)OPERATIONSEarning (loss) for the period$(22,692)$2,251Adjustments for:Unrealized gain on derivative contracts (note 9)(3,003)(4,816)Loss (gain) on sale of property, plant and equipment (note 9)3,999(1,146)Depletion and depreciation25,31825,696Impairment loss (note 4)20,000-Stock-based payments430491Accretion on decommissioning obligations (note 6, 10)637856Accretion on convertible debentures (note 10)953510Deferred income tax expense (benefit)(7,420)970Decommissioning expenditures (note 6)(365)(42)Changes in non-cash working capital (note 11)(839)1,18417,01825,954FINANCINGIncrease (decrease) in bank loans31,004(7,113)Proceeds from issue of convertible debentures, net of issue costs-43,860Proceeds from exercise of stock options-51Changes in non-cash working capital (note 11)(175)(34)30,82936,764INVESTINGProperty, plant and equipment expenditures(23,075)(74,005)Proceeds from sale of property, plant and equipment6,1995,367Changes in non-cash working capital (note 11)(30,972)1,896(47,848)(66,742)Decrease in cash and cash equivalents(1)(4,024)Cash and cash equivalents, beginning of period14,024Cash, end of period$-$-Interest received in cash$29$33Interest paid in cash$(7,377)$(990)See accompanying notes to the condensed interim consolidated financial statements.ANDERSON ENERGY LTD.Notes to the Condensed Interim Consolidated Financial StatementsTHREE AND SIX MONTHS ENDED JUNE 30, 2012 AND 2011(Tabular amounts in thousands of dollars, unless otherwise stated)(Unaudited)1. REPORTING ENTITY Anderson 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. The Company's board of directors has initiated 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 not complete and is still ongoing and the Company will continue to identify, examine and consider a full range of strategic alternatives. 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 August 10, 2012.(b) Accounting policies 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$755,738Additions26,0972626,123Disposals(29,779)-(29,779)Balance at June 30, 2012$750,193$1,889$752,082Accumulated depletion, depreciation and impairment lossesOil and natural gas assetsOther equipmentTotalBalance at January 1, 2011$265,358$1,243$266,601Depletion and depreciation for the year52,79413552,929Impairment loss35,230-35,230Disposals(5,969)-(5,969)Balance at December 31, 2011$347,413$1,378$348,791Depletion and depreciation for the period25,2467225,318Impairment loss20,000-20,000Disposals(12,823)-(12,823)Balance at June 30, 2012$379,836$1,450$381,286Carrying amountsOil and natural gas assetsOther equipmentTotalAt December 31, 2011$406,462$485$406,947At June 30, 2012$370,357$439$370,796Capitalized overhead. For the six months ended June 30, 2012, additions to property, plant and equipment included internal overhead costs of $2.1 million (year ended December 31, 2011 - $4.6 million).4. IMPAIRMENT LOSS In the second quarter of 2012, declines in forecasted natural gas commodity prices and the ongoing strategic alternatives process are indicators of impairment for certain CGUs. Forecasted natural gas commodity prices at June 30, 2012 declined between eight and 18 per cent when compared to December 31, 2011. The following table shows the differences in the future natural gas commodity prices used by the Company's independent qualified reserves evaluators at June 30, 2012 compared to December 31, 2011:AECO Gas Price ($Cdn/MMBTU)YearJune 30, 2012December 31, 2011Difference20133.444.13(0.69)20143.904.59(0.69)20154.365.05(0.69)20164.825.51(0.69)20175.285.97(0.69)20185.686.21(0.53)20195.806.33(0.53)20205.916.46(0.55)20216.036.58(0.55)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. Management's estimated reserves values used in the evaluation of recoverable amounts of certain CGUs were calculated using a discount rate of 10 per cent. At June 30, 2012, if the discount rate used had been two percent higher or two percent lower, the reserves values estimated would have been approximately $11 million lower or $13 million higher respectively. 5. BANK LOANS At June 30, 2012, total bank facilities were $135 million, consisting of a $110 million extendible revolving term credit facility, a $10 million working capital credit facility and a $15 million supplemental credit facility, with a syndicate of Canadian banks. The extendible revolving term credit facility and the working capital credit facility had a revolving period ending on July 11, 2012. The supplemental facility expired on July 11, 2012. At June 30, 2012, there were no amounts drawn under the supplemental facility. The average effective interest rate on advances under the facilities in 2012 was 4.2% (June 30, 2011 - 5.7%). The Company had approximately $0.4 million in letters of credit outstanding at June 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. Subsequent to June 30, 2012, the Company's lenders amended and extended the Company's revolving credit facility and working capital credit facility to July 10, 2013. Total bank facilities were initially set at $125 million stepping down as certain dispositions closed subsequent to June 30, 2012, to $100 million on July 31, 2012 and to $90 million on September 30, 2012. The bank lines will consist of a $10 million working capital facility and an $80 million revolving commitment as of September 30, 2012. 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. Under the new 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. 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 or at the next scheduled review. 6. DECOMMISSIONING OBLIGATIONSJune 30, 2012December 31, 2011Balance at January 1$62,848$51,550Provisions incurred8164,878Total abandonment expenditures(365)(249)Provisions disposed(5,073)(1,316)Change in estimates2786,355Accretion expense6371,630Ending balance$59,141$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 $59.1 million as at June 30, 2012 (December 31, 2011 - $62.8 million) based on an undiscounted inflation-adjusted total future liability of $75.5 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 2012 and 2030. At June 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 0.9% to 3.1% (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. Issued share capital.Number of Common sharesAmountBalance at January 1, 2011172,485,301$426,925Elimination of deficit-(255,543)Stock options exercised64,40051Transferred from contributed surplus on stock option exercise-27Balance at December 31, 2011 and June 30, 2012172,549,701$171,460Elimination 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 six months ended June 30, 2012 and the year ended December 31, 2011 are as follows:June 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(2,301,682)3.79(1,564,150)4.27Forfeited during the period(208,200)0.84(848,300)1.01Ending balance11,519,300$1.2814,014,182$1.69Exercisable, end of period4,714,333$1.946,764,582$2.60 The 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$0.494.4$0.68 to $1.026,048,9000.743.3$1.03 to $1.543,473,3501.083.2$2.33 to $3.50601,9502.701.2$3.51 to $4.901,207,6003.990.4Total at June 30, 201211,519,300$1.282.9The weighted average common share price at the date of exercise for stock options exercised in 2011 was $1.20. The fair value of the options granted in the six months ended June 30, 2012 and 2011 were estimated using the Black-Scholes model with the following weighted average inputs:June 30, 2012June 30, 2011Fair value at grant date$0.30$0.61Common share price$0.57$1.18Exercise price$0.57$1.18Volatility61%58%Option life5 years5 yearsDividends0%0%Risk-free interest rate1.3%2.7%Forfeiture rate15%15%This estimated forfeiture rate is adjusted to the actual forfeiture rate when each tranche vests. Stock-based compensation cost of $0.4 million (June 30, 2011 - $0.5 million) was expensed during the six months ended June 30, 2012. Stock-based compensation cost of $0.2 million (June 30, 2011 - $0.3 million) was expensed during the three months ended June 30 2012. In addition, stock-based compensation expense of $0.3 million (June 30, 2011 - $0.3 million) was capitalized during the six months ended June 30, 2012. For the three months ended June 30, 2012, $0.1 million of stock-based compensation was capitalized (June 30, 2011 - $0.2 million).8. EARNINGS (LOSS) PER SHARE Basic and diluted earnings (loss) per share were calculated as follows:Three months endedSix months endedJune 30, 2012June 30, 2011June 30, 2012June 30, 2011Earnings (loss) for the period$(16,828)$5,932$(22,692)$2,251Weighted average number of common shares (basic) (in thousands of shares)Common shares outstanding at beginning of period172,550172,545172,550172,485Effect of stock options exercised-3-41Weighted average number of common shares (basic)172,550172,548172,550172,526Effect of dilutive stock options-387-637Weighted average number of common shares (diluted)172,550172,935172,550173,163Basic and diluted earnings (loss) per share$(0.10)$0.03$(0.13)$0.01The 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 June 30, 2012, 11,519,300 options (June 30, 2011 - 8,673,032 options) and 59,316,889 common shares reserved for convertible debentures (June 30, 2011 - 59,316,889) were excluded from calculating dilutive earnings as they were anti-dilutive. For the six months ended June 30, 2012, 11,519,300 options (June 30, 2011 - 8,628,032 options) and 59,316,889 common share reserved for convertible debentures (June 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 endedSix months endedJune 30, 2012June 30, 2011June 30, 2012June 30, 2011Realized gain (loss) on derivative contracts$1,305$(824)$1,518$(1,224)Unrealized gain on derivative contracts4,6927,6653,0034,816Gain (loss) on sale of property, plant and equipment(1,389)761(3,999)1,146$4,608$7,602$522$4,73810. FINANCE INCOME AND EXPENSESThree months endedSix months endedJune 30, 2012June 30, 2011June 30, 2012June 30, 2011Income:Interest income on cash equivalents$-$2$-$5Other882428Expenses:Interest and financing costs on bank loans(1,244)(891)(2,284)(1,709)Interest on convertible debentures(1,772)(1,150)(3,543)(2,088)Accretion on convertible debentures(480)(291)(953)(510)Accretion on decommissioning obligations(319)(439)(637)(856)Other(7)2(9)(15)Net finance expenses$(3,814)$(2,759)$(7,402)$(5,145)11. SUPPLEMENTAL CASH FLOW INFORMATION Changes in non-cash working capital is comprised of:June 30, 2012June 30, 2011Source (use) of cashAccounts receivable and accruals$2,509$2,695Prepaid expenses and deposits893205Accounts payable and accruals(35,388)146$(31,986)$3,046Related to operating activities$(839)$1,184Related to financing activities$(175)$(34)Related to investing activities$(30,972)$1,89612. 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 June 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)$25,185$-$-$-$-Bank loans - principal (2)29,68690,000---Convertible debentures- Interest (1)5,5227,0857,0857,0853,335- Principal---50,00046,000Total$60,393$97,085$7,085$57,085$49,335(1) Accounts payable and accruals includes $1.6 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) Effective July 11, 2012, the Company's credit facilities were extended and amended. The Company's credit facility will be reduced to $90 million on September 30, 2012; accordingly, bank loans in excess of $90 million have been shown as repayable in less than one year. 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 six months ended June 30, 2012, earnings would have been affected by approximately $0.4 million (June 30, 2011 - $0.2 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 June 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 July 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 June 30, 2012, the Company estimates that it would receive approximately $4.4 million to terminate these contracts (December 31, 2011 - receive $1.4 million).The fair value of derivative contracts at June 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 $1.00 per barrel change in the oil prices$(207)$207Subsequent to June 30, 2012, the Company entered into 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. (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 $141.4 million, bank loans of $119.7 million, convertible debentures with a face value of $96.0 million and the cash working capital deficiency of $12.0 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.June 30, 2012December 31, 2011Bank loans$119,686$88,682Current liabilities(1)25,18560,573Current assets(1)(13,196)(16,599)Net debt before convertible debentures$131,675$132,656Convertible debentures (liability component)85,74984,796Total net debt$217,424$217,452Cash from operating activities in the quarter$7,712$16,462Decommissioning expenditures in the quarter58146Changes in non-cash working capital in the quarter(164)389Funds from operations in the quarter$7,606$16,997Annualized current quarter funds from operations$30,424$67,988Twelve-month trailing funds from operations$47,874$54,464Net debt before convertible debentures to funds from operations- Annualized current quarter funds from operations4.32.0- Twelve-month trailing funds from operations2.82.4Total net debt to funds from operations- Annualized current quarter funds from operations7.13.2- 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 June 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 46 per cent decline in natural gas prices and a 15 per cent decline Canadian oil prices compared to the fourth quarter of 2011. Since June 30, 2012, the Company has applied proceeds on disposition of assets of approximately $30.9 million to reduce bank loans. The Company is currently actively engaged in a process to sell additional non-strategic assets to repay bank loans and fund drilling operations in its core areas. 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 June 30, 2012, the Company had commitments for future capital expenditures in the amount of $1.5 million that are expected to be incurred during the remainder of 2012. In addition to these capital commitments, the Company has entered into "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 six gross (4.5 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 $100,000 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 third agreement, there is a $200,000 non-performance fee should the Company fail to drill the well. (b) Other commitments and contingencies. At June 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$556$1,023$812$699$110$299Firm service committed volumes (MMcfd)15148733There 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 EVENTS Subsequent to June 30, 2012, the Company sold or has entered into agreements to sell properties considered to be non-strategic assets for cash consideration of approximately $30.9 million (subject to normal course closing adjustments). Proceeds were used or will be used to repay bank loans.Corporate InformationHead Office700 Selkirk House555 4th Avenue S.W.Calgary, AlbertaCanada T2P 3E7Phone (403) 262-6307Fax (403) 261-2792Website http://www.andersonenergy.ca/DirectorsJ.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 ExchangeSymbol 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 pricebbl - barrelbpd - barrels per day BOE - barrels of oil equivalentBOED - barrels of oil equivalent per dayMBOE - thousand barrels of oil equivalentGJ - gigajoule Mcf - thousand cubic feetMcfd - thousand cubic feet per dayMMcfd - million cubic feet per dayNGL - natural gas liquidsMMBTU - million British thermal unitsWTI - West Texas IntermediateNYMEX - The New York Mercantile ExchangeFOR FURTHER INFORMATION PLEASE CONTACT: Brian H. DauAnderson Energy Ltd.President & Chief Executive Officer(403) 262-6307info@andersonenergy.cawww.andersonenergy.ca