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Press release from Marketwire

Anderson Energy Announces 2012 First Quarter Results

Monday, May 14, 2012

Anderson Energy Announces 2012 First Quarter Results09:00 EDT Monday, May 14, 2012CALGARY, ALBERTA--(Marketwire - May 14, 2012) - Anderson Energy Ltd. ("Anderson" or the "Company") (TSX:AXL) is pleased to announce its operating and financial results for the first quarter ended March 31, 2012. HIGHLIGHTSFunds from operations in the first quarter of 2012 were $10.6 million, down 2% from the first quarter of 2011. Production in the first quarter of 2012 was 7,236 BOED. The operating netback per BOE in the first quarter of 2012 was $23.62 per BOE compared to $21.96 per BOE in the first quarter of 2011. The operating netback increased in spite of a 44% decrease in natural gas prices. Cardium oil netbacks averaged $53.89 per BOE in the first quarter of 2012. Oil and NGL production averaged 2,659 bpd in the first quarter of 2012, up 28% from the same period in 2011. Oil represented 1,956 bpd of total production and was 43% higher than last year. Oil and NGL revenue represented 80% of Anderson's total oil and gas revenue compared to 57% in the first quarter of 2011. Anderson's Cardium horizontal oil location inventory is approximately 284 gross (187 net) locations, a 13% increase since reported on March 19, 2012. Net prospect inventory has increased as a result of information gained from new discoveries as well as additional farm-in and leasing transactions. In the first quarter of 2012, Anderson completed its first slick water Cardium frac. This new well was brought on-stream April 3, 2012 with a first 30 day average rate of approximately 700 BOED. 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. Anderson has engaged BMO Capital Markets and RBC Capital Markets as financial advisors to assist in this process. FINANCIAL AND OPERATING HIGHLIGHTSThree months ended March 31% Change(thousands of dollars, unless otherwise stated)20122011Oil and gas sales*$25,208$25,586(1%)Revenue, net of royalties*$22,445$23,283(4%)Funds from operations$10,616$10,868(2%)Funds from operations per share (basic and diluted)$0.06$0.06-Loss$(5,864)$(3,681)(59%)Loss per share (basic and diluted)$(0.03)$(0.02)(50%)Capital expenditures, net of proceeds on dispositions$12,090$42,354(71%)Bank loans plus cash working capital deficiency$134,437$102,97131%Convertible debentures$85,269$43,67995%Shareholders' equity$157,920$178,628(12%)Average shares outstanding (thousands)Basic172,550172,504-Diluted172,550172,504-Ending shares outstanding (thousands)172,550172,545-Average daily sales volumesNatural gas (Mcfd)27,46333,931(19%)Oil (bpd)1,9561,37243%NGL (bpd)7036991%Total barrels of oil equivalent (BOED)7,2367,726(6%)Average pricesNatural gas ($/Mcf)$2.01$3.58(44%)Oil ($/bbl)$88.48$84.714%NGL ($/bbl)$67.36$65.972%Barrels of oil equivalent ($/BOE)*$38.28$36.804%Realized gain (loss) on derivative contracts ($/BOE)$0.32$(0.57)156%Royalties ($/BOE)$4.20$3.3127%Operating costs ($/BOE)$10.61$10.63-Transportation costs ($/BOE)$0.17$0.33(48%)Operating netback ($/BOE)$23.62$21.968%Wells drilled (gross)315(80%)* Includes royalty and other income classified with oil and gas sales, but excludes the realized gain (loss) and unrealized loss on derivative contracts of $0.2 million and $(1.7) million respectively during the three months ended March 31, 2012 (March 31, 2011 - $(0.4) million and $(2.8) million respectively).NEW CARDIUM DISCOVERIES In the first quarter of 2012, Anderson completed its first slick water Cardium frac. This new well was brought on-stream April 3, 2012 with a first 30 day average rate of approximately 700 BOED (65% oil and NGL). The Company is planning to use this technology on future completions.FERRIER CARDIUM OIL POOL DEVELOPMENT UPDATE Four gross (2.5 net revenue) Cardium horizontal oil wells are on production. Anderson has expanded its oil battery gas compression system and plans to drill three additional wells in the third quarter of 2012.CARDIUM ENHANCED OIL RECOVERY Anderson has completed a computer reservoir simulation of the Garrington field to determine the most appropriate fluid and scheme for enhanced recovery of Cardium oil using horizontal oil drilling. The conclusion of the study is that a gas flood is the most economical scheme and could potentially double recovery in this oil pool. The Company plans to use its uphole Edmonton Sands gas and/or Cardium solution gas as an injection fluid to enhance recovery. The earliest injection date would be in the last quarter of 2012, subject to regulatory approval and gas compression installation.CARDIUM HORIZONTAL OIL PROSPECT INVENTORY The Company has grown its drill-ready net prospect inventory by 13% since March 19, 2012 as outlined below:Cardium Prospect AreaGrossNet *Garrington11284Willesden Green7757Ferrier3622Pembina5924Total Cardium inventory284187Oil wells drilled to May 11, 20127556Remaining Cardium inventory, May 11, 2012209131* Net is net revenue interestNet prospect inventory has increased as a result of information gained from new discoveries as well as additional farm-in and leasing transactions. Anderson has completed all of its Cardium facility construction projects. Future wells drilled from the Cardium inventory outlined above could be simply connected to the new Company-owned infrastructure. OTHER ZONE HORIZONTAL OIL PROSPECT INVENTORY The Company has identified a prospect inventory for light oil drilling in the Second White Specs ("SWS"), Viking and Belly River zones in Central Alberta. At this time, the Company has not drilled any horizontal wells into these horizons. Many of the wells identified could also be connected to existing Cardium oil infrastructure owned by the Company.A total of 91 gross (50 net) horizontal drilling locations have been identified in the SWS, Viking and Belly River zones in Central Alberta. The Company has a total of 134 gross (70.6 net) sections of land in the SWS fairway. The drilling inventory mentioned above for the SWS, is based on the Company's interpretation for horizontal oil prospectivity in the silt portion of the SWS. Industry competitors have drilled and placed on production two horizontal SWS wells offsetting Company-interest lands. The Company will be monitoring the performance of those wells to analyze the impact on its acreage. The Company used geological well control and successful industry horizontal oil analogs to identify the prospects in the Viking and Belly River. GARRINGTON BATTERY The Company and third parties are now trucking oil volumes from other areas to Anderson's Garrington Cardium oil battery. 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. As well, the Company has increased revenue by processing third party trucking volumes. Operating expenses in the Garrington Cardium project were $4.71 per BOE in the first quarter of 2012 and operating netbacks were $57.87 per BOE. PRODUCTION Production in the first quarter of 2012 was 7,236 BOED. Oil and natural gas liquids production averaged 2,659 bpd. All of the operated Cardium wells successfully drilled in the first quarter of 2012 have been placed on production to date in 2012. Overall production was lower in the first 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. 2012 CAPITAL PROGRAM For the first half of 2012, Anderson estimates its capital program to be $16 million, net of proceeds on dispositions, dedicated exclusively to its Cardium horizontal drilling program. After spring break up, the Company will revisit its 2012 capital program. COMMODITY HEDGING CONTRACTSCrude Oil. As part of its price management strategy, the Company has fixed price swap contracts based on the NYMEX crude oil price in Canadian dollars. As of May 11, 2012, the average volumes and prices for these contracts are summarized below:PeriodWeighted average volume (bpd)Weighted average WTI Canadian ($/bbl)April to December 20121,500103.87The Company entered into hedging contracts to protect its capital program and will continue to evaluate the merits of additional commodity hedging as part of a price management strategy. The Company has not hedged any natural gas volumes at this time.PROPERTY DISPOSITION UPDATE In the first quarter of 2012, Anderson closed property sales of approximately 206 BOED (76% natural gas) of production based on January 2012 production, for total consideration of $6.2 million. These properties are considered by the Company to be non-core and of no strategic value to Anderson. FINANCIAL RESULTS Capital expenditures were $12.1 million (net of proceeds on dispositions of $6.2 million) in the first quarter of 2012 with $12.3 million spent on drilling and completions and $5.1 million spent on facilities. This compares to capital expenditures of $42.4 million (net of proceeds on dispositions of $5.2 million) in the first quarter of 2011. Anderson's funds from operations were $10.6 million in the first quarter of 2012 compared to $10.9 million in the first quarter of 2011. The Company's average crude oil and natural gas liquids sales prices in the first quarter of 2012 were $88.48 and $67.36 per barrel respectively compared to $84.71 and $65.97 per barrel in the first quarter of 2011. Oil differentials between Cushing, Oklahoma and Edmonton, Alberta averaged $10.53 per bbl U.S. in the first quarter of 2012, compared to $1.46 per bbl U.S. premium in the fourth quarter of 2011 ($11.99 per bbl U.S. difference). The second quarter of 2012 differentials are expected to be similar to the first quarter of 2012, however, June 2012 differentials are currently estimated to be less than $4.00 per bbl reflecting transportation costs to Cushing, Oklahoma. The increase in the differential in the first quarter of 2012 was largely related to unplanned refinery outages and seasonal refinery turnarounds. The completion of the refinery turnarounds in the second quarter and the planned Seaway pipeline reversal are contributing to lower differentials going forward. Differentials are expected to remain volatile in the near term. During the first quarter of 2012, oil and NGL revenue represented 80% of Anderson's total oil and gas revenue compared to 57% in the first quarter of 2011. The Company has fixed price oil swaps for 2012. The Company's unrealized loss on its oil derivatives was $1.7 million for the first quarter of 2012. The Company's average natural gas sales price was $2.01 per Mcf in the first quarter of 2012 compared to $3.58 per Mcf in first quarter of 2011. The Company recorded a loss of $5.9 million in the first quarter of 2012 primarily due to declines in natural gas revenues, losses on the dispositions of non-core properties, unrealized losses on derivative contracts and higher financing expenses compared to 2011. The Company's operating netback was $23.62 per BOE in the first quarter of 2012 compared to $21.96 per BOE in the first quarter of 2011. The increase in the operating netback was primarily due to the increase in oil and NGL production volumes, which more than offset the 44% decrease in natural gas prices. Anderson's netback for its Cardium horizontal properties in the first quarter of 2012 was $53.89 per BOE (exclusive of hedging). Average wellhead natural gas price ($/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 20122.0182.9038.2823.6216.12SHUT-IN OF NATURAL GAS PROPERTIES In response to low natural gas prices, the Company has approximately 730 Mcfd of natural gas production with high operating costs shut-in and estimates that an additional 500 Mcfd could be shut-in this year. In a higher price environment, these natural gas wells could easily be returned to production.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. 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 could 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, 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 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 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. Dau President & Chief Executive Officer May 14, 2012Management's Discussion and Analysis FOR THE THREE MONTHS ENDED MARCH 31, 2012 AND 2011The following management's discussion and analysis ("MD&A") is dated May 11, 2012 and should be read in conjunction with the unaudited interim consolidated financial statements of Anderson Energy Ltd. ("Anderson" or the "Company") for the three months ended March 31, 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. The Company's 2011 capital program was focused on Cardium oil development and this had a positive impact on financial results for the three months ended March 31, 2012 when compared to the first quarter of 2011. Funds from operations were $10.6 million for the first quarter of 2012 and were similar to the first quarter of 2011 (2% decrease) despite the substantial drop in natural gas prices (44% decrease) and natural gas production (19% decrease). Compared to the fourth quarter of 2011, financial results for the first quarter of 2012 were affected by the significant drop in natural gas prices (37% decrease), lower oil prices (8% decrease) and reduced production volumes (9% decrease). Funds from operations for the first quarter of 2012 were $6.4 million lower than the fourth quarter of 2011. During the first quarter of 2012, the Company drilled three gross (2.5 net capital) Cardium oil wells with a 100% success rate and tied in seven gross (5.6 net revenue) Cardium oil wells. Capital spending was curtailed in light of significantly lower natural gas prices.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 80% of oil and gas sales in the first quarter of 2012, up 8% from the fourth quarter of 2011. Oil sales for the three months ended March 31, 2012 averaged 1,956 bpd compared to 2,122 bpd in the fourth quarter of 2011 and 1,372 bpd for the first quarter of 2011. The decrease in volumes from the fourth quarter of 2011 was due to natural production declines in excess of new production from seven gross (5.6 net revenue) Cardium oil wells brought on-stream in the quarter. 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. As a result, gas sales volumes for the three months ended March 31, 2012 decreased to 27.5 MMcfd from 33.9 MMcfd for the same period last year. Natural gas liquids sales for the three months ended March 31, 2012 averaged 703 bpd compared to 715 bpd in the fourth quarter of 2011 and 699 bpd for the first quarter of 2011. The following tables outline production revenue, volumes and average sales prices for the period ended March 31, 2012 and 2011. OIL AND NATURAL GAS SALESThree months ended March 31(thousands of dollars)20122011Natural gas$5,032$10,920Oil(1)15,74610,463NGL4,3104,149Royalty and other12054Total oil and gas sales(1)$25,208$25,586(1) Excludes the realized gain (loss) and unrealized loss on derivative contracts of $0.2 million and $(1.7) million respectively during the three months ended March 31, 2012 (March 31, 2011 - $(0.4) million and $(2.8) million respectively).PRODUCTIONThree months ended March 3120122011Natural gas (Mcfd)27,46333,931Oil (bpd)1,9561,372NGL (bpd)703699Total (BOED)7,2367,726PRICESThree months ended March 3120122011Natural gas ($/Mcf)$2.01$3.58Oil ($/bbl)(1)88.4884.71NGL ($/bbl)67.3665.97Total ($/BOE)(1)(2)$38.28$36.80(1) Excludes the realized gain (loss) and unrealized loss on derivative contracts of $0.2 million and $(1.7) million respectively during the three months ended March 31, 2012 (March 31, 2011 - $(0.4) million and $(2.8) million respectively).(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 widened dramatically in the first quarter of 2012 impacting the oil price realized by the Company. In the second quarter of 2012, average differentials are expected to be similar to the first quarter. Differentials peaked in March and April but have started to narrow significantly again for June 2012, 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 quarter of 2012. The above noted oil prices do not include a realized gain on derivative contracts of $0.2 million (March 31, 2011 - $0.4 million loss). The realized oil price including this gain was $89.68 per barrel for the first quarter of 2012 compared to $81.47 per barrel for the first quarter of 2011. Anderson's average natural gas sales price was $2.01 per Mcf for the three months ended March 31, 2012, 37% lower than the fourth quarter of 2011 price of $3.20 per Mcf and 44% lower than the first quarter of 2011 price of $3.58 per Mcf. Commodity Contracts. At March 31, 2012 the following derivative contracts were outstanding and recorded at estimated fair value:PeriodWeighted average volume (bpd)Weighted average WTI Canadian ($/bbl)April 1, 2012 to December 31, 20121,500103.87These contracts had the following impact on the consolidated statements of operations and comprehensive loss for the three months ended March 31, 2012 and 2011:Three months ended March 31(thousands of dollars)20122011Realized gain (loss) on derivative contracts$213$(400)Unrealized loss on derivative contracts(1,689)(2,849)$(1,476)$(3,249)Royalties. For the first quarter of 2012, the average royalty rate was 11.0% of revenue compared to 12.8% in the fourth quarter of 2011 and 9.0% in the first quarter of 2011. The increase in the average royalty rate for the quarter ended March 31, 2012 compared to the same period in 2011 is due to the following: (i) an estimated reduction in gas cost allowance due to lower crown royalties as a result of lower natural gas prices, production and expenditures and (ii) new production from non-crown properties that carry higher royalty rates. Offsetting this, oil wells drilled on Crown lands qualified for royalty incentives that reduced average Crown royalties during the quarter. These incentives reduce Crown royalties for periods of up to 30 months from initial production, after which Crown royalties are expected to increase from current levels. 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 March 3120122011Gross Crown royalties8.4%9.7%Gas cost allowance(4.3%)(6.9%)Other royalties6.9%6.2%Total royalties11.0%9.0%Royalties ($/BOE)$4.20$3.31Operating Expenses. Operating expenses were $10.61 per BOE for the three months ended March 31, 2012 compared to $8.30 per BOE in the fourth quarter of 2011 and $10.63 per BOE in the first quarter of 2011. Operating expenses in the first quarter of 2012 were higher than the fourth quarter of 2011 as that quarter had a reduction in estimated accrued liabilities related to certain gas plant processing fees from earlier periods. Transportation Expenses. For the three months ended March 31, 2012, transportation expenses were $0.17 per BOE compared to $0.44 per BOE in the fourth quarter of 2011 and $0.33 per BOE in the first quarter of 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 March 31(thousands of dollars)20122011Revenue (1)$25,208$25,586Realized gain (loss) on derivative contracts213(400)Royalties(2,763)(2,303)Operating expenses(6,988)(7,390)Transportation expenses(111)(233)Operating netback$15,559$15,260Sales (MBOE)658.5695.4Per BOERevenue (1)$38.28$36.80Realized gain (loss) on derivative contracts0.32(0.57)Royalties(4.20)(3.31)Operating expenses(10.61)(10.63)Transportation expenses(0.17)(0.33)Operating netback per BOE$23.62$21.96(1) Includes royalty and other income classified with oil and gas sales. Excludes unrealized loss on derivative contracts of $1.7 million (March 31, 2011 - $2.8 million loss) pertaining to fixed price crude oil swaps recorded in the first quarter of 2012.Depletion and Depreciation. Depletion and depreciation was $13.0 million ($19.81 per BOE) for the first quarter of 2012 compared to $15.0 million ($20.49 per BOE) in the fourth quarter of 2011 and $12.4 million ($17.77 per BOE) in the first quarter of 2011. The increase in depletion and depreciation for the first quarter of 2012 compared to the same period of 2011 is due to higher capital costs associated with oil properties and increased production from these properties. General and Administrative Expenses. General and administrative expenses excluding stock-based compensation were $2.1 million ($3.26 per BOE) for the three months ended March 31, 2012 compared to $2.2 million ($3.03 per BOE) in the fourth quarter of 2011 and $2.6 million ($3.80 per BOE) for the three months ended March 31, 2011. Three months ended March 31(thousands of dollars)20122011General and administrative (gross)$3,419$4,127Overhead recoveries(465 )(353 )Capitalized(808 )(1,132 )General and administrative (cash)$2,146$2,642Net stock-based compensation227234General and administrative$2,373$2,876General and administrative (cash) ($/BOE)$3.26$3.80% Capitalized24%27%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 $0.4 million in the first quarter of 2012 ($0.2 million net of amounts capitalized) compared to $0.4 million for the first quarter of 2011 ($0.2 million net of amounts capitalized).Finance Expenses. Finance expenses were $3.6 million in the first quarter of 2012, compared to $3.4 million for the fourth quarter of 2011 and $2.4 million in the first quarter of 2011. The increase in finance expenses from the first quarter of 2011 is the result of the $46 million (principal) of convertible debentures issued on June 8, 2011 at 7.25% and a higher average debt balance under the Company's credit facilities. While the average effective interest rate on outstanding bank loans was 4.0% for the three months ended March 31, 2012 compared to 6.1% for the comparable period in 2011, the Company had more bank loans outstanding in 2012.Three months ended March 31(thousands of dollars)20122011Interest and accretion on convertible debentures$2,244$1,157Interest expense on credit facilities1,042835Accretion on decommissioning obligations318417Finance expenses$3,604$2,409Decommissioning Obligations. The Company recorded a decrease of $3.7 million in decommissioning obligations in the first quarter of 2012. The Company disposed of $4.5 million in decommissioning obligations as part of minor property dispositions in the first quarter of 2012 and recorded $0.8 million relating to current drilling activity and changes in estimates. Accretion expense was $0.3 million for the first quarter of 2012 compared to $0.4 million in the first quarter of 2011 and was included in finance expenses. The risk-free discount rates used by the Company to measure the obligations at March 31, 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 $499 million in tax pools at March 31, 2012. Funds from Operations. Funds from operations for the first quarter of 2012 were $10.6 million ($0.06 per share), down 38% from the $17.0 million ($0.10 per share) recorded in the fourth quarter of 2011 and down 2% from the $10.9 million ($0.06 per share) recorded in the first quarter of 2011. The increase in funds from operations from the first quarter of 2011 to the fourth quarter of 2011 was a result of the Company's focus on oil prospects, which generate more cash flow per BOE when compared to natural gas properties. The decrease in funds from operations in the first quarter of 2012 compared to the fourth quarter of 2011 was largely due to the dramatic drop in natural gas prices during the first quarter of 2012. Lower oil prices and lower production volumes also contributed to the decline.Three months ended March 31(thousands of dollars)20122011Cash from operating activities$9,306$11,001Changes in non-cash working capital1,003(159)Decommissioning expenditures30726Funds from operations$10,616$10,868Earnings. The Company reported a loss of $5.9 million in the first quarter of 2012 compared to a loss of $32.2 million for the three months ended December 31, 2011 and a loss of $3.7 million for the first quarter of 2011. In the first quarter of 2012, losses were recorded on the disposition of non-core properties and the mark-to-market adjustment on the Company's outstanding derivatives. 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 $12.1 million on capital expenditures, net of proceeds from dispositions in the first quarter of 2012. The breakdown of expenditures is shown below:Three months ended March 31(thousands of dollars)20122011Land, geological and geophysical costs$165$287Proceeds on disposition(6,199)(5,200)Drilling, completion and recompletion12,27338,898Drilling incentive credits-153Facilities and well equipment5,1367,082Capitalized general and administrative expenses8081,132Total finding, development & acquisition expenditures12,18342,352Change in compressor and other inventory and equipment(100)-Office equipment and furniture72Total net cash capital expenditures$12,090$42,354Drilling statistics are shown below:Three months ended March 3120122011GrossNetGrossNetGas----Oil32.51513.3Dry----Total32.51513.3Success rate (%)100%100%100%100%During the first quarter of 2012, the Company drilled three gross (2.5 net capital) Cardium horizontal light oil wells. In addition, the Company brought seven gross (5.6 net revenue) Cardium horizontal light wells on-stream. During the first quarter of 2012, the Company sold minor properties for proceeds of $6.2 million and recognized a loss on sale of $2.6 million, mostly attributable to the disposition of non-operated coal bed methane properties. SHARE INFORMATION The Company's shares have been listed on the Toronto Stock Exchange since September 7, 2005 under the symbol "AXL". As of May 11, 2012, there were 172.5 million common shares outstanding, 12.1 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 first quarter of 2011, 60,000 common shares were issued under the employee stock option plan. There were no common shares issued under the employee stock option plan in the first quarter of 2012.Three months ended March 3120122011High$0.68$1.36Low$0.48$1.00Close$0.57$1.21Volume16,251,28061,575,839Shares outstanding at March 31172,549,701172,545,301Market capitalization at March 31$98,353,330$208,779,814The statistics above include trading on the Toronto Stock Exchange only. Shares also trade on alternative platforms like Alpha, Chi-X, Pure and Omega. Approximately 8.2 million common shares traded on these alternative exchanges in the three months ended March 31, 2012 (March 31, 2011 - 43.5 million). Including these exchanges, an average of 0.4 million common shares traded per day in the first quarter of 2012 (March 31, 2011 - 1.7 million), representing a quarterly turnover ratio of 14% (March 31, 2011 - 61%). LIQUIDITY AND CAPITAL RESOURCES At March 31, 2012, the Company had outstanding bank loans of $106.7 million, convertible debentures of $96.0 million (principal) and a cash working capital deficiency (excluding unrealized loss on derivative contracts) of $27.8 million. The working capital deficiency is largely due to accounts payable and accruals associated with the capital program at the end of the quarter and will be funded through the available credit facilities, future operating cash flows and minor property sales. The following table shows the changes in bank loans plus cash working capital deficiency: Three months ended(thousands of dollars)March 31, 2012December 31, 2011Bank loans plus cash working capital deficiency, beginning of period$(132,656)$(108,583)Funds from operations10,61616,997Net cash capital expenditures(12,090)(40,924)Decommissioning expenditures(307)(146)Bank loans plus cash working capital deficiency, end of period$(134,437)$(132,656)The Company is committed to drill 74 gross Edmonton Sands gas wells under its farm-in agreement by March 31, 2013. The Company does not plan to drill any additional Edmonton Sands gas wells until the first quarter of 2013. The Company's need for capital will be both short-term and long-term in nature. Short-term capital is required to finance accounts receivable and other similar short-term assets while the acquisition and development of oil and natural gas properties requires larger amounts of long-term capital. Anderson will prudently use its bank loan facilities to finance its operations as required. Capital spending for the first half of 2012 is expected to be approximately $16 million net of proceeds on dispositions and will be funded by cash flow from operations. Remaining cash flow will be used to pay down bank debt. The Company plans to fund its 2012 capital program from a combination of cash flow, existing credit facilities and asset dispositions. Oil and natural gas prices will impact the level of capital spending in 2012. At March 31, 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. The extendible revolving term credit facility and the working capital credit facility have a revolving period ending on July 11, 2012. If not extended, the extendible revolving term credit facility and working capital credit facility cease to revolve and all outstanding advances thereunder become repayable one year from the term date of July 11, 2012. The supplemental facility expires on July 11, 2012, with any outstanding amounts due in full at that time. At March 31, 2012, there were no amounts drawn under the supplemental facility. The available lending limits under the bank facilities are reviewed twice a year and are based on the bank syndicate's interpretation of the Company's reserves and future commodity prices. The last review was conducted in November 2011. There can be no assurance that the amount of the available bank lines will not be adjusted at the next scheduled review before July 11, 2012. 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 March 31, 2012, these obligations include:Loan agreements - The reserves-based extendible, revolving term credit facility and working capital credit facility have a revolving period ending on July 11, 2012, extendible at the option of the lenders. If not extended, the facilities cease to revolve and all outstanding advances thereunder become repayable one year from the term date of July 11, 2012. The supplemental facility is available on a revolving basis and expires on July 11, 2012 with any amounts outstanding due in full at that time. No amounts were drawn under the supplemental facility at March 31, 2012. Letters of credit - Letters of credit of approximately $0.2 million had been issued in the normal course of business as at March 31, 2012. Convertible debentures - The Company has $96.0 million (principal) in convertible debentures outstanding at March 31, 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 18 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 dates ranging from August 1, 2012 to September 30, 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. 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 March 31, 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 284 gross (187 net revenue) drill-ready Cardium horizontal oil locations, of which 75 gross (56 net revenue) have been drilled to May 11, 2012. The Company continues to add to its land position and drilling inventory through a combination of acquisitions, property swaps and farm-ins, and continues to implement new technologies to control and reduce its costs in this project. 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 and estimates that an additional 500 Mcfd could be shut-in this year. 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. 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. In 2010 and 2011, earnings were 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 first quarter of 2012 were affected by lower natural gas prices, larger differentials between WTI and Alberta oil prices and lower production volumes. Earnings for this quarter were also reduced by a $2.6 million loss recognized on the sale of minor properties. SELECTED QUARTERLY INFORMATION($ amounts in thousands, except per share amounts and prices)Q1 2012Q4 2011Q3 2011Q2 2011Revenue, net of royalties$22,445$28,457$24,970$27,776Funds from operations$10,616$16,997$12,655$13,944Funds from operations per share, basic and diluted$0.06$0.10$0.07$0.08Earnings (loss) before effect of impairments or reversals thereof$(5,864)$ (4,939)$6,667$5,932Earnings (loss) per share before effect of impairments or reversals thereof, basic and diluted$(0.03)$(0.03)$0.04$0.03Earnings (loss)$(5,864)$(32,167)$7,472$5,932Earnings (loss) per share, basic and diluted$(0.03)$(0.19)$0.04$0.03Capital expenditures, including acquisitions net of proceeds on dispositions$12,090$40,924$49,713$26,284Cash from operating activities$9,306$16,462$11,893$14,953Daily salesNatural gas (Mcfd)27,46330,57630,03831,990Oil (bpd)1,9562,1221,7091,759NGL (bpd)703715636667BOE (BOED)7,2367,9337,3517,758Average pricesNatural gas ($/Mcf)$2.01$3.20$3.85$3.79Oil ($/bbl)(2)$88.48$96.33$89.05$99.39NGL ($/bbl)$67.36$72.71$66.07$74.24BOE ($/BOE)(1)(2)$38.28$44.70$42.16$44.71Q1 2011Q4 2010Q3 2010Q2 2010Revenue, net of royalties$23,283$21,690$17,263$18,622Funds from operations$10,868$9,282$7,876$8,923Funds from operations per share, basic and diluted$0.06$0.05$0.05$0.05Loss before effect of impairments$(3,681)$(4,864)$(3,057)$(2,450)Loss per share before effect of impairments, basic and diluted$(0.02)$(0.03)$(0.02)$(0.01)Loss$(3,681)$(36,545)$(39,029)$(4,769)Loss per share, basic and diluted$(0.02)$(0.21)$(0.23)$(0.03)Capital expenditures, including acquisitions net of proceeds on dispositions$42,354$26,240$39,378$12,664Cash from operating activities$11,001$10,488$8,287$8,811Daily salesNatural gas (Mcfd)33,93138,47935,77838,998Oil (bpd)1,372992568491NGL (bpd)699823761741BOE (BOED)7,7268,2287,2927,732Average pricesNatural gas ($/Mcf)$3.58$3.48$3.43$3.78Oil ($/bbl)(2)$84.71$77.62$68.24$70.45NGL ($/bbl)$65.97$58.87$51.41$53.55BOE ($/BOE)(1)(2)$36.80$31.63$28.21$28.88(1) Includes royalty and other income classified with oil and gas sales. (2) Excludes realized and unrealized gains (losses) on derivative contracts as follows: 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 alternative review process and enhancement of shareholder value, disclosure intentions with respect to the strategic alternative review process; 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; 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. CONVERSONDisclosure 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)March 31, 2012December 31, 2011ASSETSCurrent assets:Cash$-$1Accounts receivables and accruals14,45614,272Prepaid expenses and deposits1,7412,326Unrealized gain on derivative contracts (note 11)-1,38416,19717,983Deferred tax asset37,26835,389Property, plant and equipment (note 3)399,844406,947$453,309$460,319LIABILITIES AND SHAREHOLDERS' EQUITYCurrent liabilities:Accounts payable and accruals$43,979$60,573Unrealized loss on derivative contracts (note 11)305-44,28460,573Bank loans (note 4)106,65588,682Convertible debentures85,26984,796Decommissioning obligations (note 5)59,18162,848295,389296,899Shareholders' equity:Share capital (note 6)171,460171,460Equity component of convertible debentures5,0195,019Contributed surplus9,7499,385Deficit (note 6)(28,308)(22,444)157,920163,420Commitments and contingencies (note 12)$453,309$460,319See accompanying notes to the condensed interim consolidated financial statements. ANDERSON ENERGY LTD. Consolidated Statements of Operations and Comprehensive LossTHREE MONTHS ENDED MARCH 31, 2012 AND 2011 (Stated in thousands of dollars, except per share amounts) (Unaudited)20122011Oil and gas sales$25,208$25,586Royalties(2,763)(2,303)Revenue, net of royalties22,44523,283Other expenses (note 8)(4,086)(2,864)18,35920,419Operating expenses6,9887,390Transportation expenses111233Depletion and depreciation13,04212,355General and administrative expenses2,3732,876Loss from operating activities(4,155)(2,435)Finance income (note 9)1623Finance expenses (note 9)(3,604)(2,409)Net finance expenses(3,588)(2,386)Loss before taxes (7,743)(4,821)Deferred income tax benefit(1,879)(1,140)Loss and comprehensive loss for the period$(5,864)$(3,681)Basic and diluted loss per share (note 7)$(0.03)$(0.02)See accompanying notes to the condensed interim consolidated financial statements.ANDERSON ENERGY LTD. Consolidated Statements of Changes in Shareholders' Equity THREE MONTHS ENDED MARCH 31, 2012 AND 2011(Stated in thousands of dollars, except number of common shares) (Unaudited)Number of common sharesShare capitalEquity component of convertible debenturesContributed surplusDeficitTotal shareholders' equityBalance at January 1, 2011172,485,301$426,925$2,592$7,921$(255,543)$181,895Share-based payments---366-366Options exercised60,00073-(25)-48Loss for the period----(3,681)(3,681)Balance at March 31, 2011172,545,301$426,998$2,592$8,262$(259,224)$178,628Balance at January 1, 2012172,549,701$171,460$5,019$9,385$(22,444)$163,420Share-based payments---364-364Loss for the period----(5,864)(5,864)Balance at March 31, 2012172,549,701$171,460$5,019$9,749$(28,308)$157,920See accompanying notes to the condensed interim consolidated financial statements.ANDERSON ENERGY LTD. Consolidated Statements of Cash FlowsTHREE MONTHS ENDED MARCH 31, 2012 AND 2011(Stated in thousands of dollars) (Unaudited)20122011CASH PROVIDED BY (USED IN)OPERATIONSLoss for the period$(5,864)$(3,681)Adjustments for:Unrealized loss on derivative contracts (note 8)1,6892,849(Gain) loss on sale of property, plant and equipment (note 8)2,610(385)Depletion and depreciation13,04212,355Stock-based payments227234Accretion on decommissioning obligations (note 5)318417Accretion on convertible debentures473219Deferred income tax benefit(1,879)(1,140)Decommissioning expenditures (note 5)(307)(26)Changes in non-cash working capital (note 10)(1,003)1599,30611,001FINANCINGIncrease in bank loans17,9736,528Proceeds from exercise of stock options-48Changes in non-cash working capital (note 10)(175)(294)17,7986,282INVESTINGProperty, plant and equipment expenditures(18,289)(47,554)Proceeds from sale of property, plant and equipment6,1995,200Changes in non-cash working capital (note 10)(15,015)21,047(27,105)(21,307)Decrease in cash and cash equivalents(1)(4,024)Cash and cash equivalents, beginning of period14,024Cash, end of period$-$-Interest received in cash$21$23Interest paid in cash$(4,747)$(517)See accompanying notes to the condensed interim consolidated financial statements.ANDERSON ENERGY LTD. Notes to the Condensed Interim Consolidated Financial Statements THREE MONTHS ENDED MARCH 31, 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 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. 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. 2. BASIS OF PREPARATION(a) Statement of compliance. The 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 interim consolidated financial statements were authorized for issuance by the Board of Directors on May 11, 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. 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 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$755,738Additions19,950719,957Disposals(24,358)-(24,358)Balance at March 31, 2012$749,467$1,870$751,337Accumulated 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 period13,0053713,042Disposals(10,340)-(10,340)Balance at March 31, 2012$350,078$1,415$351,493Carrying amountsOil and natural gas assetsOther equipmentTotalAt December 31, 2011$406,462$485$406,947At March 31, 2012$399,389$455$399,844Capitalized overhead. For the three months ended March 31, 2012, additions to property, plant and equipment included internal overhead costs of $0.9 million (year ended December 31, 2011 - $4.6 million). 4. BANK LOANS At March 31, 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 have a revolving period ending on July 11, 2012. If not extended, the extendible revolving term credit facility and working capital credit facility cease to revolve and all outstanding advances thereunder become repayable one year from the term date of July 11, 2012. The supplemental facility expires on July 11, 2012, with any outstanding amounts due in full at that time. At March 31, 2012, there were no amounts drawn under the supplemental facility. The average effective interest rate on advances under the facilities in 2012 was 4.0% (March 31, 2011 - 6.1%). The Company had $184,600 in letters of credit outstanding at March 31, 2012 that reduce the amount of credit available to the Company. Advances under the facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank's prime lending rate, bankers' acceptance or LIBOR loan rates plus applicable margins. These margins vary from 1.50% to 6.00% depending on the borrowing option used and the Company's financial ratios. Loans are secured by a floating charge debenture over all assets and guarantees by material subsidiaries. The available lending limits of the facilities are reviewed semi-annually and are based on the bank syndicate's interpretations of the Company's reserves and future commodity prices. There can be no assurance that the amount of the available facilities or the applicable margins will not be adjusted at the next scheduled review on or before July 11, 2012. 5. DECOMMISSIONING OBLIGATIONSMarch 31, 2012December 31, 2011Balance at January 1$62,848$51,550Provisions incurred5964,878Total abandonment expenditures(307)(249)Provisions disposed(4,461)(1,316)Change in estimates1876,355Accretion expense3181,630Ending balance$59,181$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 $59.2 million as at March 31, 2012 (December 31, 2011 - $62.8 million) based on an undiscounted inflation-adjusted total future liability of $75.9 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 March 31, 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. 6. 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 March 31, 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 period ended March 31, 2012 and the year ended December 31, 2011 are as follows:March 31, 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(145,000)1.89(1,564,150)4.27Forfeited during the period(21,000)0.98(848,300)1.01Ending balance13,863,182$1.6914,014,182$1.69Exercisable, end of period6,757,615$2.586,764,582$2.60The range of exercise prices of the outstanding options is as follows:Range of exercise pricesNumber of optionsWeighted average exercise priceWeighted average remaining life (years)$0.45 to $0.67187,500$0.494.6$0.68 to $1.026,206,1000.743.6$1.03 to $1.543,554,9501.073.4$2.33 to $3.50601,9502.701.5$3.51 to $4.903,312,6824.000.3Total at March 31, 201213,863,182$1.692.7The 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 was estimated using the Black-Scholes model with the following weighted average inputs:March 31, 2012March 31, 2011Fair value at grant date$0.30$0.61Common share price$0.57$1.19Exercise price$0.57$1.19Volatility61%58%Option life5 years5 yearsDividends0%0%Risk-free interest rate1.3%2.6%Forfeiture rate15%15%This estimated forfeiture rate is adjusted to the actual forfeiture rate when each tranche vests. Stock-based compensation cost of $0.2 million (March 31, 2011 - $0.2 million) was expensed during the three months ended March 31, 2012. In addition, stock-based compensation expense of $0.2 million (March 31, 2011 - $0.1 million) was capitalized during the three months ended March 31, 2012. 7. LOSS PER SHARE Basic and diluted loss per share were calculated as follows:March 31, 2012March 31, 2011Loss for the period$(5,864)$(3,681)Weighted average number of common shares (basic)(in thousands of shares)Common shares outstanding at January 1172,550172,485Effect of stock options exercised-19Weighted average number of common shares (basic)172,550172,504Basic and diluted loss per share$(0.03)$(0.02)The average market value of the Company's common shares for purposes of calculating the dilutive effect of stock options was based on quoted market prices for the period that the options were outstanding. For the three months ended March 31, 2012, 13,863,182 options (March 31, 2011 - 11,278,332 options) and 59,316,889 common shares reserved for convertible debentures (March 31, 2011 - 32,258,065) were excluded from calculating dilutive earnings as they were anti-dilutive. 8. OTHER EXPENSES Other expenses include the following:March 31, 2012March 31, 2011Realized gain (loss) on derivative contracts$213$(400)Unrealized loss on derivative contracts(1,689)(2,849)Gain (loss) on sale of property, plant and equipment(2,610)385$(4,086)$(2,864)9. FINANCE INCOME AND EXPENSESMarch 31, 2012March 31, 2011IncomeInterest income on cash equivalents$-$3Other1620ExpensesInterest and financing costs on bank loans(1,040)(818)Interest on convertible debentures(1,771)(938)Accretion on convertible debentures(473)(219)Accretion on decommissioning obligations(318)(417)Other(2)(17)Net finance expenses$(3,588)$(2,386)10. SUPPLEMENTAL CASH FLOW INFORMATION Changes in non-cash working capital is comprised of:March 31, 2012March 31, 2011Source (use) of cashAccounts receivable and accruals$(184)$2,417Prepaid expenses and deposits585245Accounts payable and accruals(16,594)18,250$(16,193)$20,912Related to operating activities$(1,003)$159Related to financing activities$(175)$(294)Related to investing activities$(15,015)$21,04711. 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 March 31, 2012:Financial LiabilitiesLess than one yearOne to two yearsTwo to three yearsThree to four yearsFour to five yearsFive to six yearsNon-derivative financial liabilitiesAccounts payable and accruals (1)$43,979$-$-$-$-$-Bank loans - principal (2)-106,655----Convertible debentures- Interest (1)5,6267,0857,0857,0853,3351,667- Principal---50,000-46,000Total$49,605$113,740$7,085$57,085$3,335$47,667(1) Accounts payable and accruals includes $1.5 million of interest relating to convertible debentures. The total cash interest payable in less than one year on the convertible debentures is $7.1 million.(2) Assumes the credit facilities are not renewed on July 11, 2012. (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 three months ended March 31, 2012, earnings would have been affected by approximately $180,000 (March 31, 2011 - $86,400) based on the average bank debt balance outstanding during the period.Commodity price risk. Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for oil and natural gas are impacted by both the relationship between the Canadian and U.S. dollar and world economic events that dictate the levels of supply and demand. At March 31, 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 April 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 March 31, 2012, the Company estimates that it would pay approximately $0.3 million to terminate these contracts (December 31, 2011 - receive $1.4 million). The fair value of the financial commodity risk management contracts have been allocated to current and non-current liabilities on a contract by contract basis as follows:March 31, 2012December 31, 2011Current asset$-$1,384Current liability(305)-Net asset (liability) position$(305)$1,384The fair value of derivative contracts at March 31, 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 $1.00 per barrel change in the oil prices$(309)$309(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 $157.9 million, bank loans of $106.7 million, convertible debentures with a face value of $96.0 million and the cash working capital deficiency of $27.8 million, which excludes the current portion of unrealized losses 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 IFRS and therefore are referred to as non-GAAP measures.March 31, 2012December 31, 2011Bank loans$106,655$88,682Current liabilities(1)43,97960,573Current assets(1)(16,197)(16,599)Net debt before convertible debentures$134,437$132,656Convertible debentures (liability component)85,26984,796Total net debt$219,706$217,452Cash from operating activities in the quarter$9,306$16,462Decommissioning expenditures in the quarter307146Changes in non-cash working capital in the quarter1,003389Funds from operations in the quarter$10,616$16,997Annualized current quarter funds from operations$42,464$67,988Twelve-month trailing funds from operations$54,212$54,464Net debt before convertible debentures to funds from operations- Annualized current quarter funds from operations3.22.0- Twelve-month trailing funds from operations2.52.4Total net debt to funds from operations- Annualized current quarter funds from operations5.23.2- Twelve-month trailing funds from operations4.14.0(1) Excludes unrealized gains (losses) on derivative contracts. There were no changes in the Company's approach to capital management during the three months ended March 31, 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 37% decline in natural gas prices and an 8% decline Canadian oil prices compared to the fourth quarter of 2011. 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.12. COMMITMENTS AND CONTINGENCIES(a) Capital commitments. At March 31, 2012, the Company had commitments for future capital expenditures in the amount of $0.3 million that are expected to be incurred during the second quarter 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. In certain farm-in agreements, the Company is subject to non-performance fees if it does not fulfill its capital spending obligations. There are no material changes to commitments pursuant to the farm-in agreements disclosed in the Company's annual audited consolidated financial statements as at and for the years ended December 31, 2011 and 2010.(b) Other commitments and contingencies. At March 31, 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$923$956$794$695$110$299Firm service committed volumes (MMcfd)18128733There 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.Corporate InformationContact InformationHead OfficeAnderson Energy Ltd.700 Selkirk HouseBrian H. Dau555 4th Avenue S.W.President & Chief Executive OfficerCalgary, Alberta(403) 262-6307Canada T2P 3E7 info@andersonenergy.ca Phone (403) 262-6307Fax (403) 261-2792OfficersWebsite http://www.andersonenergy.ca/J.C. AndersonDirectorsChairman of the BoardJ.C. Anderson(4)Brian H. DauCalgary, AlbertaPresident & Chief Executive OfficerBrian H. Dau David M. SpykerCalgary, AlbertaChief Operating OfficerChristopher L. Fong (1)(2)(3)(4) Calgary, AlbertaM. Darlene WongVice President Finance, Chief Financial Officer & SecretaryGlenn D. Hockley (1)(3)(4)Calgary, AlbertaBlaine M. ChicoineVice President, Drilling and CompletionsDavid J. Sandmeyer (2)(3)(4)Calgary, AlbertaSandra M. DrinnanVice President, LandDavid G. Scobie (1)(2)(4)Calgary, AlbertaPhilip A. HarveyVice President, ExploitationMember of:(1) Audit CommitteeJamie A. Marshall(2) Compensation & CorporateVice President, ExplorationGovernance Committee(3) Reserves CommitteePatrick M. O'Rourke(4) Special Committee Vice President, ProductionAuditorsAbbreviations usedKPMG LLPbbl - barrelbpd - barrels per day Independent EngineersGLJ Petroleum Consultants Ltd.BOE - barrels of oil equivalentBOED - barrels of oil equivalent per dayMBOE - thousand barrels of oil equivalentLegal CounselMcf - thousand cubic feetBennett Jones LLP Mcfd - thousand cubic feet per dayMMcfd - million cubic feet per dayRegistrar & Transfer AgentNGL - natural gas liquidsValiant Trust Company WTI - West Texas IntermediateNYMEX - The New York Mercantile ExchangeStock ExchangeThe Toronto Stock ExchangeSymbol AXL, AXL.DB, AXL.DB.B FOR FURTHER INFORMATION PLEASE CONTACT: Brian H. DauAnderson Energy Ltd.President & Chief Executive Officer(403) 262-6307info@andersonenergy.cawww.andersonenergy.ca