Anderson Energy Announces 2012 Fourth Quarter and Year End Results

CALGARY, ALBERTA–(Marketwire – March 18, 2013) – Anderson Energy Ltd. (“Anderson” or the “Company”) (TSX:AXL) is pleased to announce its operating and financial results for the fourth quarter and year ended December 31, 2012.

• The Company completed its Cardium horizontal light oil winter drilling program using slick water frac technology. Initial production results were vastly superior to previously used fracture stimulation techniques. The average initial production rate over the first 30 days for the seven wells that used this technology was 455 BOED. With the completion of the Company’s winter drilling program, all of its drilling commitments have been fulfilled.
• Anderson closed all of the previously announced property dispositions prior to year end. Approximately $74 million in properties were sold during 2012.
• Bank debt was reduced significantly to $48.1 million at December 31, 2012 ($88.7 million – 2011) and bank loans plus cash working capital deficiency was reduced to $64.5 million ($132.7 million – 2011).
• Funds from operations were $5.7 million for the fourth quarter of 2012 and $29.6 million for the year ended December 31, 2012.
• Production in the fourth quarter of 2012 was 4,500 BOED, which includes 645 BOED related to properties sold in the quarter. Net of all of the properties sold, the Company estimates first quarter 2013 production to be approximately 3,900 to 4,200 BOED (43% oil and NGL).
• The Company’s operating netback per BOE increased throughout the year to $26.50 per BOE in the fourth quarter of 2012 compared to $22.71 per BOE for the year. Cardium operating netbacks averaged $44.32 per BOE in the fourth quarter of 2012 and $44.73 per BOE for the year.
• Proved plus probable (“P&P”) BOE reserves are 17.8 MMBOE at December 31, 2012.
• Cardium P&P reserves are 13.3 MMBOE representing 75% of total P&P reserves volumes and 90% of total P&P reserves value on a pre-tax 10% net present value (“NPV 10”) basis. Full cycle three year average finding, development and acquisition costs (“FD&A”) including future development capital in the Cardium play were $36.77 per BOE on a total proved (“TP”) basis and $25.81 per BOE on a P&P basis. For the same three year period, the Cardium P&P recycle ratio was 2.03.
• Oil and NGL represent a larger proportion of total reserves: 39% of the Company’s proved developed producing (“PDP”) reserves, 43% of TP reserves and 48% of P&P reserves compared to 33%, 29% and 31% respectively at December 31, 2011. Cardium properties represent 96% of the Company’s P&P oil and NGL reserves and 55% of the Company’s P&P natural gas reserves (primarily solution gas).
• Anderson’s total P&P pre-tax NPV 10 reserves value at December 31, 2012 was $224.8 million.
• 232 additional gross (148 net) Cardium drilling locations (97% Company operated) have been identified of which only 32% on a net basis are recognized as P&P locations in the GLJ Report (as defined herein).
• The Company’s average oil price was $83.21 per bbl for the year. The Cardium oil production is light, sweet oil that was subject to an average price differential of $7.87 US per bbl in 2012.

• selling $74 million of non-strategic assets, which were primarily natural gas assets and other miscellaneous properties, and although production on a BOED basis is lower, the remaining production is more valuable as it is primarily related to the higher netback Cardium assets;
• reducing bank debt to $48.1 million at December 31, 2012 from $106.7 million at March 31, 2012 with the proceeds from the sale of assets;
• restructuring all of its shallow gas and Cardium drilling commitments such that by the end of January 2013, Anderson had completed all of its drilling commitments; and
• reducing its head office staff count and head office leasing costs.

The Company estimates its first quarter 2013 production will be 3,900 to 4,200 BOED, of which approximately 55% is from high netback Cardium properties. Oil and NGL production is estimated to be approximately 43% of total BOED production in the quarter.

Total Company operating netbacks averaged $26.50 per BOE in the fourth quarter of 2012. Cardium operating netbacks averaged $44.32 per BOE in the fourth quarter. Operating netbacks per BOE in the first quarter of 2013 are estimated to be similar to the fourth quarter of 2012. Full cycle three year average FD&A costs including future development capital in the Cardium play were $36.77 per BOE on a TP basis and $25.81 on a P&P basis. Using three year production weighted average Cardium operating netbacks, this yields a recycle ratio of 2.03 on a P&P basis.

The Company’s first slick water frac completion was in February 2012. Since then, six new wells were frac’d with this technique, yielding substantially better initial production rates and economics. The Company continues to be an industry pacesetter for low costs with Cardium horizontal drilling and completion costs in this past winter’s program averaging $2.3 million per well. The wells drilled in the past winter are connected via short tie-ins to the Company’s pre-built infrastructure which reduced equipping and tie-in costs. The Company was able to drill wells in 10 to 15 days depending on the depth drilled, slick water fracture stimulate the wells approximately seven days later and have new oil production the following day, for an impressive cycle time average of 20 days.

The Company has seen five consecutive years of long term gas price declines by its independent reserves engineers. The Company no longer has any undeveloped shallow gas reserves contained in the reserves evaluation as of December 31, 2012. The Company’s shallow gas land, drilling locations and infrastructure awaits better natural gas pricing before drilling and well tie-in operations can resume. Today, 75% of the Company’s P&P reserves are located in the Cardium properties, and these Cardium properties comprise 90% of the pre-tax NPV 10 value of the Company.

Anderson has not drilled a gas well since mid-2010, and has been entirely focused on converting its historical shallow gas asset base into a Cardium light oil horizontal development company. This transition to light oil is necessary. The average NYMEX natural gas price in 2012 was $2.83 US per MMBtu. This resulted in an average natural gas price received by the Company of $2.21 per mcf in 2012, and the lowest natural gas price seen in the Company’s 11 year history. To put this price in perspective, the Company’s average natural gas price from 2009 to 2011 was $3.84 per mcf, and from 2006 to 2008 was $7.04 per mcf. In contrast, light oil prices remain very good, and unlike the heavy oil “bitumen bubble” which has caused heavy oil price differentials to widen out, the light oil price differential (i.e. the difference between the Edmonton par reference price and the WTI Cushing price) was $7.87 US per bbl in 2012, and is estimated to be $6.08 US per bbl in March 2013. All of the Company’s oil production is light oil. Anderson realized a field oil price (excluding hedging) of $83.21 per bbl in 2012 and estimates it will be slightly higher in the first quarter of 2013. Today, Anderson has the advantage of being totally focused on light oil development drilling in the Cardium formation with 165 gross (90 net) sections of Cardium prospective land. Our Cardium net drilling inventory increased by 35% in the past 12 months to 232 gross (148 net) drilling locations, and 74% of the net drilling inventory can be connected to our owned and operated facilities.

In 2012, the Garrington Cardium area net operating income (revenue minus royalties minus operating expenses) was $54.27 per BOE, with average operating expenses net of processing income of $4.85 per BOE. The Garrington Cardium property is the Company’s largest Cardium property and represents approximately 47% of the Company’s total pre-tax NPV 10 valuation. In 2012, its average production was 958 BOED and TP and P&P reserves were 3,771 and 6,120 MBOE respectively. This property contains a strategic 100% owned and operated oil battery and truck terminal which connects to the light oil Plains Rangeland pipeline system. The Company has been steadily increasing third party truck volumes from 50 m³ per day in early 2012 to over 250 m³ per day at the present time. The Company is investigating options to reconfigure this facility to substantially increase and attract third party truck volumes.

In addition to the substantive Cardium light oil drilling inventory, the Company has identified an important new play on its lands – the Second White Specks. The Company has 104 gross (46 net) sections of Second White Specks (“2WS”) land and has assembled a drilling inventory of 102 gross (59 net) drilling locations. This zone is 100 meters deeper than the Cardium formation and is the oil-source zone for the Cardium play and is oil-charged with similar quality light oil that is in the Cardium formation. To date, other operators have drilled six horizontal oil 2WS wells offsetting the Company lands. The Company believes this play can be exploited by drilling off existing Cardium drilling pads and handling the Second White Specks oil and solution gas at the Company’s operated Cardium facilities.

The Company no longer considers itself to be a shallow gas production and development company. The Company is a light oil horizontal development company focused almost exclusively on the Cardium with a stacked resource play in the Second White Specks. The Company’s assets are almost entirely west of the fifth meridian, and a two hour drive north of Calgary on predominantly year-round access land. With a new reserves report, excellent drilling results yielding high initial productivity, relatively low capital costs and an expanded drilling inventory, the Company continues to explore its options through a strategic alternatives process. Anderson has prepared a confidential data room to assist in this process. Qualified parties have signed confidentiality agreements to review information in this data room.

With recent property dispositions and existing bank lines, the Company was able to complete all of its recently restructured drilling commitments. This winters drilling program has demonstrated significant initial production results for slick water frac stimulations that were vastly superior to previously announced techniques. The Company continues to add to its Cardium drilling inventory.

STRATEGIC ALTERNATIVES

The Company is continuing its 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 may include, but are not limited to, a sale of all or a material portion of the assets of Anderson, or a drilling joint venture, 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 discount to the value of the underlying assets, especially given its high quality light oil production base, prospective horizontal light 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 the 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.

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 or the impact it will have on the Company’s financial position. The Company has not set a definitive schedule to complete the evaluation.

* Includes royalty and other income classified with oil and gas sales, but excludes realized and unrealized gains or losses on derivative contracts. 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.

WINTER DRILLING PROGRAM

Anderson has completed its winter drilling program with 6 gross (4.3 net revenue) Cardium oil wells drilled, completed and on production. The Company has completed all of its drilling commitments on third party lands. Wells were drilled in the Ferrier, Willesden Green, Garrington and Buck Lake project areas. Drilling and completion costs were approximately $2.3 million per well in this program.

SLICKWATER FRAC TECHNOLOGY

In February 2012, Anderson initiated its first slick water frac completion in the Cardium. The Company had previously employed gelled water and gelled hydrocarbon frac techniques. Encouraged by the success of its first slick water frac completion and recent industry activity in slick water frac technology, the Company used slick water fracs on its six well Cardium horizontal drilling program this winter. Production information from the seven wells confirms that initial production is significantly higher when slick water frac technology is used in the Cardium formation compared to previously used gelled water and gelled hydrocarbon frac techniques. This conclusion is supported by industry activity offsetting Company interest lands. For the wells drilled by the Company that were completed using slick water frac technology, the average initial production (“IP”) performance for various calendar day averages is shown below:

* 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.

Short term production rates can be influenced by flush production effects from fracture stimulations in horizontal wellbores and may not be indicative of longer term production performance. Individual well performance can vary.

DRILLING INVENTORY

The Company’s drilled and drill-ready light oil horizontal drilling inventory is outlined below:

* Net is net revenue interest

The Company’s remaining Edmonton Sands shallow gas drilling inventory is now estimated to be 542 gross (307 net) locations.

The recently completed reserves report effective December 31, 2012, and summarized herein, includes proved plus probable reserves for 48 net Cardium horizontal oil, 0.75 net other horizontal oil and no Edmonton Sands locations. There are a further 100 net Cardium horizontal and 61 net other horizontal light oil locations that are not included in the reserves report.

PRODUCTION

The property dispositions announced in the fourth quarter of 2012 have all been completed. Net of all of the properties sold, the Company estimates first quarter 2013 production to be approximately 3,900 to 4,200 BOED of which 55% is from high netback Cardium properties. Oil & NGL production is estimated to be 43% of the total BOED production in the quarter. Given the low price environment, the Company shut-in 700 Mcfd of natural gas production in the first quarter of 2012, and shut-in an additional 900 Mcfd in the first quarter of 2013.

2013 CAPITAL PROGRAM

For the first half of 2013, Anderson estimates its capital program to approximate cash flows, dedicated exclusively to its Cardium horizontal drilling program. After spring break up, the Company will revisit its 2013 capital program.

COMMODITY HEDGING CONTRACTS

Crude Oil. As part of its price management strategy, the Company has added to its fixed price swap contracts based on the NYMEX crude oil price in Canadian dollars. As of March 15, 2013, the average volumes and prices for these derivative contracts are summarized below:

The Company entered into hedging contracts to protect its capital program and continues 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.

RESERVES

GLJ Petroleum Consultants (“GLJ”), an independent evaluator, has completed a reserves report (the “GLJ Report”) of all the Company’s oil and natural gas properties effective December 31, 2012, prepared in accordance with procedures and standards contained in National Instrument 51-101 of the Canadian Securities Administrators (“NI 51-101”) and the Canadian Oil and Gas Evaluation (“COGE”) Handbook. The reserves definitions used in preparing the report are those contained in the COGE Handbook and NI 51-101. As of December 31, 2012, the Company had 6.9 MMBOE PDP reserves (39% oil & NGL), 10.3 MMBOE TP reserves (43% oil & NGL) and 17.8 MMBOE P&P reserves (48% oil & NGL). The GLJ price forecast used in the evaluation is shown in Management’s Discussion and Analysis for the year ended December 31, 2012.

The reserves report reflects the disposition of $74 million in properties in 2012, the previously announced termination of the Company’s shallow gas drilling commitment and the negative impact of significant reductions in natural gas price forecasts over the past year. The percentage of PDP, TP and P&P total BOE reserves volumes from the Cardium formation represent approximately 59%, 66% and 75% of total Company reserves volumes respectively. By product, approximately 96% of P&P oil and NGL reserves and 55% of P&P natural gas reserves (primarily solution gas) are in the Cardium formation. The Cardium P&P NPV 10 value is approximately 90% of the total Company P&P NPV 10 value. The Edmonton Sands shallow gas project represents approximately 5% of the total Company P&P NPV 10 value.

SUMMARY OF OIL AND GAS RESERVES

Finding, development and acquisition (“FD&A”) costs on a total company basis were indeterminate in 2012, as the Company’s proceeds from selling assets exceeded its field capital program expenditures. The Company believes that finding and development costs should include acquisition and disposition costs as these functions are not segregated operationally in the Company, and it is a useful and commonly used reference for shareholders and analysts. In the Cardium play, full-cycle, three year average FD&A costs including future development capital were $36.77 per BOE on a TP basis and $25.81 per BOE on a P&P basis. This compares to 2012 one year FD&A costs of $1.15 per BOE on a TP basis and $3.12 per BOE on a P&P basis and 2011 one year FD&A costs of $39.16 per BOE on a TP basis and $26.68 per BOE on a P&P basis. Using three-year production weighted average Cardium operating netbacks, this yields a recycle ratio of 2.03 before hedging gains, on a P&P basis. The aggregate of the exploration, development and acquisition costs incurred in the most recent financial year and the change during the year in estimated future development costs generally will not reflect total FD&A costs related to reserve additions for that year.

The Company’s reserve life indices are 7.0 years TP and 12.0 years P&P based on an annualized mid-point estimate of the first quarter production for 2013.

Anderson’s P&P pre-tax NPV 10 at December 31, 2012 was $224.8 million, 37% lower than at December 31, 2011 as a result of the property sales in the year and lower price forecasts used by GLJ. At December 31, 2012, GLJ’s natural gas price and Edmonton crude oil price forecasts for the years 2013 to 2021 were an average of $0.91 per MMBtu and $7.63 per bbl lower respectively than they were last year.

In 2012, the Company experienced negative technical revisions of 0.5 MMBOE TP and 1.0 MMBOE P&P as well as negative economic factor revisions of 1.8 MMBOE TP and 4.1 MMBOE P&P. These negative economic factors were related to the reduction of undeveloped natural gas reserves in the Edmonton Sands formation.

The Company disposed of 7.1 MMBOE TP and 11.4 P&P reserves. Approximately 75% of the TP and 81% of the P&P dispositions were due to the $74 million in property sales during 2012. Dispositions also include 1.8 MMBOE TP and 2.2 MMBOE P&P reserves associated with the cancellation of the Edmonton Sands drilling commitment. The Company was able to cancel its previous Edmonton Sands farm-in commitment in exchange for a carried interest in one net Cardium horizontal well from this winter’s drilling program. The cancellation of the Edmonton Sands commitment combined with the economic factor revision for this area, plus minor changes to the Cardium future development capital, caused a significant reduction in future development capital compared to the previous year’s reserve report. Future development capital on TP reserves is $66.8 million as compared to $149.8 million on last year’s report, and is $145.3 million for P&P reserves, as compared to $264.9 million last year.

The Company will provide more detailed information regarding its December 31, 2012 reserves report as part of its annual information form filing in March 2013.

FINANCIAL RESULTS

Capital expenditures were $10.1 million in the fourth quarter of 2012 with $8.3 million spent on drilling and completions and $1.3 million spent on facilities. This compares to capital expenditures of $41.0 million in the fourth quarter of 2011. Proceeds from the sale of assets were $37.0 million in the fourth quarter of 2012.

Anderson’s funds from operations were $5.7 million in the fourth quarter of 2012 compared to $17.0 million in the fourth quarter of 2011. The Company’s average crude oil and natural gas liquids sales prices in the fourth quarter of 2012 were $79.73 and $52.02 per barrel compared to $96.33 and $72.71 respectively per barrel in the fourth quarter of 2011. The Company’s average natural gas sales price was $3.16 per Mcf in the fourth quarter of 2012 compared to $3.20 per Mcf in fourth quarter of 2011. The Company recorded a loss of $8.9 million in the fourth quarter of 2012 compared to a loss of $32.2 million in the fourth quarter of 2011. The Company’s operating netback was $26.50 per BOE in the fourth quarter of 2012 compared to $29.88 per BOE in the fourth quarter of 2011. The decrease in the operating netback was primarily due to the decrease in oil and NGL prices and oil volumes. Anderson’s operating netback for its Cardium horizontal properties in the year ended December 31, 2012 was $44.73 per BOE compared to $6.07 per BOE for the remainder of its properties (exclusive of hedging). Anderson’s operating netback for its Cardium properties was $44.32 per BOE in the fourth quarter of 2012.

STRATEGY

Subject to the outcome of the strategic alternatives process, the Company intends to continue to focus on converting its asset base so that more than 50% of its production is from oil and NGL.

Brian H. Dau

President & Chief Executive Officer

March 18, 2013

Management’s Discussion and Analysis

FOR THE YEARS ENDED DECEMBER 31, 2012 AND 2011

The following management’s discussion and analysis is dated March 15, 2013 and should be read in conjunction with the audited consolidated financial statements of Anderson Energy Ltd. (“Anderson” or the “Company”) for the years ended December 31, 2012 and 2011. The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) and interpretations of the International Financial Reporting Interpretations Committee (“IFRIC”).

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, and gains or losses on sale of property, plant and equipment. 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, BOEs 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 additional 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 RESULTS

Overview. Anderson focused on improving its overall financial position during 2012. Proceeds from the disposition of properties have been used to pay down bank loans and fund a modest level of capital spending. However, the dispositions have contributed to lower production volumes and related cash flows from operations. The natural declines of oil and gas production, shut-ins of uneconomic gas production, lower capital spending during 2012 and comparatively lower commodity prices have also impacted operating and financial results for the year ended December 31, 2012 compared to 2011.

Bank loans plus cash working capital deficiency (excludes unrealized gain or loss on derivative contracts) decreased to $64.5 million at December 31, 2012 from $132.7 million at December 31, 2011. Funds from operations of $29.6 million for 2012 were 46% lower than 2011 as a result of the substantial drop in natural gas prices (39% decrease), declines in NGL prices (18% decrease), oil prices (11% decrease) and overall lower production volumes (21% decrease). Funds from operations for the fourth quarter of 2012 were $5.7 million, consistent with the third quarter of 2012, but were $11.3 million lower than the fourth quarter of 2011 primarily due to reduced production volumes (43% decrease).

The Company drilled 7 gross (6.5 net capital) new wells during the 2012 financial year; 3 gross (2.5 net capital) wells early in the year and 4 gross (4 net capital) wells in the fourth quarter. Of the wells drilled in the fourth quarter, 2 gross (1.3 net revenue) wells were brought on late in the fourth quarter and the remaining 2 gross (1.5 net revenue) wells were brought on early in 2013. An additional 2 gross (1.75 net capital, 1.5 net revenue) wells were drilled and brought on production early in 2013.

Revenue and production for the fourth quarter and year ended December 31, 2012 declined substantially when compared to the same periods ended December 31, 2011 for three main reasons:

During the year ended December 31, 2012, Anderson sold interests in 17 properties for total consideration of $73.9 million (2011 – $11.6 million). Total production sold was approximately 2,292 BOED (71% natural gas) and includes 54 BOED of dry gas swapped in exchange for additional interests in Cardium drillable lands at Garrington.

The Company suspended its shallow gas drilling program prior to 2011 because of low natural gas prices, and curtailed its oil drilling program during 2012 due to the strategic review process and limited funds. Accordingly, natural production declines were not replaced, resulting in decreases in gas sales throughout 2011 and 2012, and declines in oil production in 2012. In addition, early in the year the Company shut-in over 700 Mcfd of natural gas production that was uneconomical to produce in the current price environment, thus contributing to lower natural gas sales during 2012.

Approximately 1,534 BOED of total production was sold in the fourth quarter of 2012, contributing to the decline in production from 5,770 BOED in the third quarter to 4,500 BOED in the fourth quarter of 2012. As the properties were sold part way through the quarter, there was still 645 BOED of production from these properties reported in the fourth quarter of 2012.

The Company estimates first quarter 2013 production to be approximately 3,900 to 4,200 BOED of which 43% is estimated to be from oil and natural gas liquids production.

Prices. For the 2012 financial year, natural gas prices fell to near historic lows, and the Company benefitted from the change in focus to oil beginning in 2010 as oil and natural gas liquids production volumes represented 35% of total BOED production (2011 – 31%), partially mitigating the impact of low natural gas prices. In the fourth quarter of 2012, oil and natural gas liquids production volumes represented 33% of total BOED production (fourth quarter of 2011 – 36%).

World and North American benchmark prices for oil remain volatile and as described below, the Company has entered into certain derivative contracts to partially hedge oil prices. Differentials between WTI oil prices and prices received in Alberta are affected by factors including refining demand and pipeline capacity. Light, sweet oil differentials between Cushing, Oklahoma and Edmonton, Alberta were adversely affected by transportation and market factors beginning late in 2011 and continuing into 2012. These differentials averaged $10.53 US per bbl discount in the first quarter of 2012, and improved to $10.25, $7.21 and $3.49 US per bbl in the second, third and fourth quarter of 2012 respectively. The average differential for the year ended December 31, 2012 was a $7.87 US per bbl discount, compared to an average $1.46 US per bbl premium as recently as the fourth quarter of 2011. Going into 2013, light, sweet oil differentials are expected to be comparable to the annual average rate during 2012 and may remain volatile in the future depending on supply, transportation alternatives and refining demand.

Natural gas prices were low throughout 2011. Market conditions, including high supply and low demand due to a warm winter in North America, resulted in the reduction in natural gas prices during the first six months of 2012. However, the increased demand for natural gas for electrical power generation during the hot summer throughout North America contributed to modest price gains in the last half of the year.

The above noted oil price in 2012 does not include a realized gain on derivative contracts of $5.4 million (December 31, 2011 – $0.6 million loss). The realized oil price including this gain was $101.08 per barrel for the fourth quarter of 2012 and $93.06 per barrel for the year, compared to $94.94 per barrel for the fourth quarter of 2011 and $92.06 for the year ended December 31, 2011.

The Company’s average natural gas sales price was $3.16 per Mcf for the three months ended December 31, 2012, 41% higher than the third quarter of 2012 price of $2.24 per Mcf and 1% lower than the fourth quarter of 2011 price of $3.20 per Mcf. For the year ended December 31, 2012, the Company’s average natural gas sales price was $2.21 per Mcf compared to $3.60 per Mcf for 2011. The natural gas price for the year ended 2012 includes a gain of $0.1 million on the Company’s fixed price natural gas contracts, compared to a gain of $1.2 million for 2011.

Commodity contracts. At December 31, 2012, the following derivative contracts were outstanding and recorded at estimated fair value:

By comparison, WTI Canadian averaged $103.04 per bbl in the first quarter of 2012, $94.29 per bbl in the second quarter of 2012, $91.70 per bbl in the third quarter and $87.39 per bbl in the fourth quarter of 2012.
Derivative contracts had the following impact on the consolidated statements of operations:

In October 2012, 500 bpd of derivative contracts for the months of November and December 2012 were settled for a gain of $0.4 million which was reflected in the financial results for the fourth quarter of 2012.

Fixed price contracts. The Company entered into physical contracts to sell 7,000 GJs per day of natural gas for August and September 2012 at an average AECO price of $2.45 per GJ. The Company realized a gain on fixed price natural gas contracts of $0.1 million for the year ended December 31, 2012 as compared to a gain of $1.2 million for the year ended December 31, 2011.

Royalties. For the year ended December 31, 2012, the average rate for royalties was 10.3% of revenue (December 31, 2011 – 11.8%). For the fourth quarter of 2012, the average rate for royalties was 9.7% of revenue compared to 10.2% of revenue in the third quarter of 2012 and 12.8% of revenue in the fourth quarter of 2011. The decrease in the average royalty rate for the year and quarter ended December 31, 2012 is due to reduced royalty rates at lower commodity prices. Oil wells drilled on Crown lands during 2011 and 2012 qualified for royalty incentives that reduce average 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 and year to year.

Operating expenses. Operating expenses were $12.11 per BOE for the three months ended December 31, 2012 compared to $11.28 per BOE in the third quarter of 2012 and $8.30 per BOE in the fourth quarter of 2011. The lower operating expense for the fourth quarter of 2011 was primarily due to a reduction in estimated accrued liabilities related to certain gas plant processing fees from earlier periods. Operating expenses were $10.90 per BOE for the year ended December 31, 2012 compared to $10.52 per BOE in 2011.

Transportation expenses. For the year ended December 31, 2012, transportation expenses were $0.22 per BOE (December 31, 2011 – $0.58 per BOE). For the fourth quarter of 2012, transportation expenses were $0.10 per BOE compared to $0.13 per BOE in the third quarter of 2012 and $0.44 per BOE in the fourth 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.

Depletion and depreciation. Depletion and depreciation was $44.4 million ($19.96 per BOE) for the year ended December 31, 2012 compared to $52.9 million ($18.85 per BOE) in 2011. Depletion and depreciation was $9.0 million ($21.70 per BOE) in the fourth quarter of 2012 compared to $10.1 million ($19.01 per BOE) in the third quarter of 2012 and $15.0 million ($20.49 per BOE) in the fourth quarter of 2011. The decrease in the amount of depletion and depreciation for the year and the fourth quarter of 2012 compared to the same periods of 2011 is due to lower overall production volumes. Proved plus probable reserves volumes are included in the determination of depletion expense. Natural gas reserves volumes were reduced due to low natural gas prices, property dispositions, and the termination of the Edmonton Sands farm-in agreement, thus resulting in higher depletion and depreciation expense per BOE.

Impairment loss. Oil and natural gas assets are grouped into cash generating units (“CGUs”) for impairment testing. The Company had previously grouped its development and production assets into the following CGUs: Horizontal Oil, Deep Gas, Shallow Gas and Non-Core. In 2012, a significant portion of the assets in the Deep Gas and Non-core CGUs were sold and the remaining assets were regrouped into the following CGUs: Gas, and Horizontal Cardium. The Horizontal Cardium CGU retained the same group of assets, but was renamed to better reflect the nature of those assets. The remaining assets in the Deep Gas and Non-core CGUs more closely resemble the operational, management and monitoring, product composition, and cash inflows of the assets within the Shallow Gas CGU. Accordingly, the remaining Deep Gas and Non-core assets have been grouped with the Shallow Gas assets to form the new Gas CGU.

In 2012, declines in forecasted commodity prices were indicators of impairment. Forecasted commodity prices at December 31, 2012 declined between 14% and 18% for natural gas and between 4% and 16% for light, sweet crude oil when compared to December 31, 2011. In the second quarter of 2012, the Company tested its gas-weighted CGUs for impairment and determined that the aggregate carrying value of these CGUs was $20 million higher than the recoverable amounts and impairments were recorded ($13 million for the Shallow Gas CGU and $7 million for the Deep Gas CGU). In the third and fourth quarters of 2012, the Company tested all of its CGUs for impairment and determined that no additional charges for impairment were required.

General and administrative expenses. General and administrative expenses excluding share-based compensation were $2.5 million ($6.07 per BOE) for the fourth quarter of 2012 compared to $2.1 million ($3.88 per BOE) in the third quarter of 2012 and $2.2 million ($3.03 per BOE) for the fourth quarter of 2011. For the year ended December 31, 2012, general and administrative expenses excluding share-based compensation were $9.2 million ($4.12 per BOE) compared to $9.4 million ($3.36 per BOE) for 2011. The decrease in cash general and administrative expenses is the result of lower employee compensation associated with reduced staff and decreased audit and tax fees as the comparative period in 2011 had higher fees associated with the adoption of IFRS. In the fourth quarter of 2012, the Company laid off some of its staff. One time severance costs of $0.5 million were recorded in the fourth quarter. Beginning in December 2012, office rent decreased by $0.1 million per month as a result of the corporate office move into lower cost office space.

Capitalized general and administrative costs are limited to compensation and benefits and associated office rent of staff involved in capital activities.

Share-based compensation. The Company accounts for share-based compensation plans using the fair value method of accounting. Share-based compensation expense was $1.0 million in 2012 ($0.8 million net of amounts capitalized) versus $1.5 million ($1.0 million net of amounts capitalized) in 2011. Share-based compensation costs were $0.1 million for the fourth quarter of 2012 ($0.2 million net of amounts capitalized) versus $0.3 million ($0.2 million net of amounts capitalized) in the fourth quarter of 2011.

Finance expenses. Finance expenses were $3.5 million for the fourth quarter of 2012, compared to $3.9 million in the third quarter of 2012 and $3.4 million in the fourth quarter of 2011. Finance expenses were $14.8 million for the year ended December 31, 2012, compared to $11.9 million in the comparable period of 2011. The increase in finance expenses from 2011 is the result of higher interest and accretion on the $96 million (principal) of convertible debentures issued on December 31, 2010 and June 8, 2011 at 7.5% and 7.25% respectively, partially offset by lower accretion on decommissioning obligations. The average effective interest rate on outstanding bank loans was 4.7% for the year ended December 31, 2012 compared to 5.3% for the comparable period in 2011.

Decommissioning obligations. In the fourth quarter of 2012, the Company disposed of $9.7 million in decommissioning obligations related to property dispositions, and increased decommissioning obligations by $0.3 million primarily relating to drilling activity in the quarter. Accretion expense was $0.2 million for the fourth quarter of 2012 compared to $0.2 million in the third quarter of 2012 and $0.3 million in the fourth quarter of 2011 and was included in finance expenses. The decommissioning liability at December 31, 2012 decreased by $16.4 million compared to December 31, 2011, primarily due to the disposition of $20.9 million of provisions related to the sale of assets during the year. Provisions incurred were $1.2 million, down from the $4.9 million incurred during 2011 due to lower capital expenditures in 2012. Changes in estimates added $2.7 million ($2011 – $6.4 million) to the provision, and accretion expense added $1.1 million (2011 – $1.6 million).

The risk-free discount rates used by the Company to measure the obligations at December 31, 2012 were between 1.0% and 2.5% (December 31, 2011 – 0.9% to 3.1%) depending on the timelines to reclamation and decreased from the start of the year as a result of changes in the Canadian bond market.

Income taxes. Anderson is not currently taxable and has the following estimated tax pool balances at December 31, 2012. Non-capital losses are estimated assuming certain discretionary claims related to tax pools are made in the current year. Tax pool classifications are estimates as some new wells have not yet had their status as exploratory or development confirmed.

Funds from operations. Funds from operations for the fourth quarter of 2012 were $5.7 million ($0.03 per share), substantially equivalent to the $5.7 million ($0.03 per share) recorded in the third quarter of 2012 and down 66% from the $17.0 million ($0.10 per share) recorded in the fourth quarter of 2011. Funds from operations for the year ended December 31, 2012 were $29.6 million ($0.17 per share), down 46% from the $54.5 million ($0.32 per share) recorded for 2011. Property dispositions contributed to lower funds from operations in 2012. The decrease in funds from operations compared to 2011 is also due to lower commodity prices for natural gas (39%), oil (11%) and NGLs (18%) in the year ended December 31, 2012 versus the year ended December 31, 2011. Production declines in natural gas, oil and NGLs of 24%, 14% and 13% respectively in the year ended December 31, 2012 compared to December 31, 2011 also contributed to lower funds from operations in 2012.

Earnings. The Company reported a loss of $8.9 million in the fourth quarter of 2012 compared to earnings of $0.1 million for the third quarter of 2012 and a loss of $32.2 million for the fourth quarter of 2011. In the fourth quarter of 2012, earnings were impacted by losses recognized on the Company’s asset dispositions. Overall, the dispositions during the 2012 financial year resulted in a net loss on sale of property, plant and equipment in the amount of $0.7 million (2011 – gain of $4.7 million).

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:

This sensitivity analysis was calculated by applying different pricing, interest rate and exchange rate assumptions to the 2012 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 $10.1 million on capital expenditures and proceeds on dispositions were $37.0 million in the fourth quarter of 2012. Capital expenditures were $34.9 million for the year ended December 31, 2012 and proceeds on disposition were $73.9 million. The breakdown of expenditures is shown below:

For the year ended December 31, 2012, the Company drilled 7 gross (6.5 net capital) Cardium horizontal wells. Of the total 7 gross wells drilled, the Company drilled 4 gross (4 net capital) Cardium horizontal wells in the fourth quarter of 2012. The Company completed its winter drilling program with an additional 2 gross (1.75 net capital, 1.5 net revenue) wells drilled during the first quarter of 2013.

RESERVES

The Company’s reserves were evaluated by GLJ Petroleum Consultants (“GLJ”) in accordance with National Instrument 51-101 (“NI 51-101”) as of December 31, 2012, prepared in accordance with procedures and standards contained in the Canadian Oil and Gas Evaluation (“COGE”) Handbook. The reserves definitions used in preparing the report are those contained in the COGE Handbook and the Canadian Securities Administrators National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). The tables in this section are excerpts from what will be contained in the Company’s Annual Information Form for the year ended December 31, 2012 (“AIF”) as the Company’s NI 51-101 annual required filings.

At December 31, 2012, the Company’s proved developed producing (“PDP”), total proved (“TP”) and proved plus probable (“P&P”) reserves were 6.9 MMBOE, 10.3 MMBOE and 17.8 MMBOE respectively.

Oil and NGL reserves now represent 39% of the Company’s PDP, 43% of TP and 48% of the P&P reserves as compared to 33%, 29% and 31% respectively at December 31, 2011.

GROSS WORKING INTEREST OIL AND GAS RESERVES⁽¹⁾

As at December 31, 2012

NET PRESENT VALUE BEFORE INCOME TAXES⁽¹⁾⁽²⁾

As at December 31, 2012

GLJ December 31, 2012 Price Forecast, Escalated Prices

The estimated net present value of future net revenues presented in the table above does not necessarily represent the fair market value of the Company’s reserves.

Total future development costs included in the reserves evaluation were $66.8 million for total proved reserves and $145.3 million for proved plus probable reserves. Further details related to future development costs, including assumptions regarding the timing of the expenditures, will be included in the Company’s AIF for the 2012 fiscal year. Future development costs are associated with the reserves as disclosed in the GLJ report and do not necessarily represent the Company’s current exploration and development budget.

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS

As at December 31, 2012

GLJ Forecast Prices and Costs

The Company’s reserves life indices are 7.0 years total proved and 12.0 years proved plus probable, based on the midpoint of the estimated first quarter 2013 production. With an average $0.91 per MMBtu reduction in GLJ’s natural gas price outlook and $7.63 per bbl decrease in Edmonton crude oil in the years 2013 to 2021, the Company experienced a negative revision for economic factors of 1.8 MMBOE for total proved and 4.1 MMBOE for proved plus probable reserves. The economic factors negative revision was almost entirely related to the Company’s undeveloped gas reserves in the Edmonton Sands properties. In addition to the economic factors, the Company experienced negative technical revisions of 0.5 MMBOE total proved and 1.0 MMBOE proved plus probable reserves. Reserves additions before revisions were 1.0 MMBOE total proved and 2.1 MMBOE proved plus probable, predominantly from Cardium oil horizontal drilling.

FINDING, DEVELOPMENT AND ACQUISITION COSTS – CARDIUM PROPERTIES ONLY

Year Ended December 31, 2012

FD&A costs on a total company basis were indeterminate in 2012, as the Company’s proceeds from selling assets exceeded its field capital program expenditures. The Company believes that finding and development costs should include acquisition and disposition costs as these functions are not segregated operationally in the Company, and it is a useful and commonly used reference for shareholders and analysts. In the Cardium play, full cycle three year average FD&A costs including future development capital were $36.77 per BOE on a TP basis and $25.81 per BOE on a P&P basis. This compares to 2012 one year FD&A costs of $1.15 per BOE on a TP basis and $3.12 per BOE on a P&P basis and 2011 one year FD&A costs of $39.16 per BOE on a TP basis and $26.68 per BOE on a P&P basis. The aggregate of the exploration, development and acquisition costs incurred in the most recent financial year and the change during the year in estimated future development costs generally will not reflect total FD&A costs related to reserve additions for that year.

SHARE INFORMATION

The Company’s shares have been listed on the Toronto Stock Exchange since September 7, 2005 under the symbol “AXL”. As of March 15, 2013, there were 172.5 million common shares outstanding, 14.3 million stock options outstanding, $50.0 million principal amount of convertible debentures which are convertible into common shares at a conversion price of $1.55 per common share and $46.0 million principal amount of convertible debentures which are convertible into common shares at a conversion price of $1.70 per common share. During 2012, no common shares (2011 – 64,400) were issued under the employee stock option plan.

SHARE PRICE ON TSX

The statistics above include trading on the Toronto Stock Exchange only. Shares also trade on alternative platforms like Alpha, Chi-X, Pure and Omega. Approximately 20 million common shares traded on these alternative exchanges in 2012 (2011 – 99.7 million). Including these exchanges, an average of 260,556 common shares traded per day in 2012 (2011 – 966,254), representing a turnover ratio of 38% (2011 – 140%).

RELATED PARTY TRANSACTIONS

On June 8, 2011, the Company issued 1,575 Series B Convertible Debentures to management and directors at a price of $1,000 per convertible debenture for total gross proceeds of $1.6 million as part of a $46.0 million bought deal offering of convertible debentures.

LIQUIDITY AND CAPITAL RESOURCES

At December 31, 2012, the Company had outstanding bank loans of $48.1 million, convertible debentures of $96.0 million (principal) and a cash working capital deficiency (excludes unrealized gain on derivative contracts) of $16.4 million. The working capital deficiency is largely due to accruals associated with the capital program in the last quarter of the year and will be funded through the available credit facilities and future operating cash flows. The following table shows the changes in bank loans plus cash working capital deficiency:

The continued development of the Company’s oil and gas assets are dependent on the ability of the Company to secure sufficient funds through operations, bank facilities and other sources from the strategic alternative 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 had commitments to drill five horizontal wells in the Cardium formation on or before March 1, 2013 and earned an average 70 per cent working interest in the wells. The commitments were met for four of the wells prior to December 31, 2012, and the remaining commitment was met in January 2013. The Company does not have any other outstanding drilling commitments as at December 31, 2012.

At December 31, 2012, the Company had total credit facilities of $65 million, consisting of a $55 million revolving term credit facility and a $10 million working capital credit facility with a syndicate of Canadian banks. Advances can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, bankers’ acceptance or LIBOR loan rates plus applicable margins. These margins vary from 3% to 4% depending on the borrowing option used. At December 31, 2012, no amounts were drawn in U.S. funds. The Company had $16.5 million of credit available at December 31, 2012. Anderson will prudently use its bank loan facilities to finance its operations as required.

For the first half of 2013, Anderson estimates its capital program to approximate cash flows, dedicated exclusively to its Cardium horizontal drilling program. After spring break up, the Company will revisit its 2013 capital program.

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 on December 15, 2012. The revolving term credit facility and the working capital credit facility have a maturity date of July 10, 2013, and all outstanding advances become repayable on July 10, 2013. There can be no assurance that the amount of the available bank lines will not be adjusted at the next scheduled review to be completed prior to May 15, 2013.

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 December 31, 2012, these obligations include:

• Loan agreements – The reserves-based revolving term credit facility and working capital credit facility have a maturity date of July 10, 2013. If not renewed, all outstanding advances thereunder become repayable on July 10, 2013.
• Firm service transportation commitments – The Company has entered into firm service transportation agreements for approximately 10 million cubic feet per day of gas sales for various terms expiring between 2013 and 2020.
• Cardium Horizontal Well Program (Oil) – At December 31, 2012 the Company had an obligation to drill one Cardium horizontal oil well. This commitment was fulfilled in the first quarter of 2013.
• Head office lease -The Company entered into an agreement to lease office space at a rate of approximately $597,000 per year ending June 30, 2014.
• Crude oil transportation contract – The term volume commitment relates to the Garrington oil facility through which the Company ships significant volumes of oil. The Company expects to exceed the term volume commitment during 2013.

These obligations are described further in notes 19 and 21 to the consolidated financial statements for the years ended December 31, 2012 and 2011.

CRITICAL ACCOUNTING ESTIMATES

The Company’s significant accounting policies are disclosed in note 3 to the consolidated financial statements. Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. These accounting policies are discussed below and are included to aid the reader in assessing the critical accounting policies and practices of the Company and the likelihood of materially different results than reported. The Company’s management reviews its estimates regularly. The emergence of new information and changed circumstances may result in actual results that differ materially from current estimates.

Oil and gas reserves. Proved and probable reserves, as defined by the Canadian Securities Administrators in NI 51-101 with reference to the Canadian Oil and Gas Evaluation Handbook, are estimated using independent reserves evaluator reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. There should be a 50 percent statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as proved and probable and a 50 percent statistical probability that it will be less. The equivalent statistical probabilities for the proved component of proved and probable reserves are 90 percent and 10 percent, respectively. Determination of reserves is a complex process involving judgments, estimates and decisions based on available geological, engineering, production and any other relevant data. These estimates are subject to material change as economic conditions change and ongoing production and development activities provide new information.

Purchase price allocations, depletion and depreciation and amounts used in impairment calculations are based on estimates of oil and gas reserves. Reserves estimates are based on engineering data, estimated future prices, expected future rates of production and timing of future capital expenditures. By their nature, these estimates are subject to measurement uncertainties and interpretations and the impact on the financial statements could be material. The Company expects that over time, its reserves estimates will be revised upward or downward based on updated information such as the results of future drilling, testing and production levels and may be affected by changes in commodity prices.

Recoverable amounts of CGUs. The recoverable amount of a CGU used in the assessment of impairment is the greater of its value-in-use (“VIU”) and its fair value less costs to sell (“FVLCTS”). VIU is determined by estimating the present value of the future net cash flows from the continued use of the CGU, and is subject to the risks associated with estimating the value of reserves. FVLCTS refers to the amount obtainable from the sale of a CGU in an arm’s length transaction between knowledgeable, willing parties, less costs of disposal. The criteria used in the estimation of this amount are discussed in note 5 to the consolidated financial statements.

At December 31, 2012 the recoverable amounts of the Company’s CGUs were based on their estimated FVLCTS. Note 5 outlines the factors considered in estimating these amounts. The key assumptions and estimates of the value of oil and gas reserves and the existing and potential markets for the Company’s oil and gas assets are made at the time of reserves estimation and market assessment and are subject to change as new information becomes available. Changes in international and regional factors including supply and demand of commodities, inventory levels, drilling activity, currency exchange rates, weather, geopolitical and general economic environment factors may result in significant changes to the estimated recoverable amounts of CGUs.

Decommissioning obligations. The Company is required to set up a provision for future removal and site restoration costs. The Company must estimate these costs in accordance with existing laws, contracts or other policies. These estimated costs are charged to property, plant and equipment and the appropriate liability account over the expected service life of the asset. The estimate of future removal and site restoration costs involves a number of estimates related to timing of abandonment, determination of the economic life of the asset, costs associated with abandonment and site restoration, discount rates and review of potential abandonment methods.

Income taxes. The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ from that estimated and recorded by management. The Company estimates its future income tax rate in calculating its future income tax liability. Various assumptions are made in assessing when temporary differences will reverse and this will impact the rate used.

Allowance for doubtful accounts. The Company maintains an allowance for doubtful accounts to provide for receivables which may ultimately be uncollectible. The allowance is determined in light of a number of factors including company specific conditions, economic events and the Company’s historical loss experience. The allowance is assessed quarterly by a detailed formal review of accounts receivable balances.

Share-based compensation. In order to recognize share-based compensation costs, the Company estimates the fair value of stock options granted using assumptions related to interest rates, expected life of the option, forfeitures, volatility of the underlying security and expected dividend yields. These assumptions may vary over time.

NEW AND PENDING ACCOUNTING STANDARDS

Standards that are issued and that the Company reasonably expects to be applicable at a future date are listed below.

IFRS 9 – Financial Instruments. IFRS 9, as issued, reflects the first phase of the IASB’s work on the replacement of IAS 39 and applies to classification and measurement of financial assets as defined in IAS 39. The standard is effective for annual periods beginning on or after January 1, 2015. In subsequent phases, the IASB will address classification and measurement of financial liabilities, hedge accounting and derecognition.

IFRS 10 – Consolidated Financial Statements. IFRS 10 requires an entity to consolidate an investee when it is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. IFRS 10 replaces SIC-12 Consolidation – Special Purpose Entities and parts of IAS 27 Consolidated and Separate Financial Statements. The standard is effective for annual periods beginning on or after January 1, 2013.

IFRS 11 – Joint Arrangements. IFRS 11 requires a venturer to classify its interest in a joint arrangement as a joint venture or a joint operation. Joint ventures will be accounted for using the equity method of accounting whereas for a joint operation the venturer will recognize its share of the assets, liabilities, revenue and expenses of the joint operation. IFRS 11 supersedes IAS 31 Interests in Joint Ventures and SIC-13 Jointly Controlled Entities – Non-Monetary Contributions by Venturers. The standard is effective for annual periods beginning on or after January 1, 2013.

IFRS 12 – Disclosure of Interests in Other Entities. IFRS 12 applies to entities that have an interest in a subsidiary, a joint arrangement, an associate or an unconsolidated structured entity. This standard is effective for annual period beginning on or after January 1, 2013.

IFRS 13 – Fair Value Measurements. IFRS 13 defines fair value, sets out in a single IFRS framework for measuring value and requires disclosure about fair value measurements. IFRS 13 applies to IFRSs that require or permit fair value measurements or disclosures about fair value measurement, except in specified circumstances. The standard is effective for annual periods beginning on or after January 1, 2013.

The Company has not completed its assessment of the impact of the above standards.

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 at the financial year end of the Company, 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 ICOFR have been designed to provide reasonable assurance that all assets are safeguarded, transactions are appropriately authorized and to facilitate the preparation of relevant, reliable and timely information. The CEO and CFO have evaluated and tested the design and operating effectiveness of Anderson’s ICOFR as of December 31, 2012 and have concluded that these internal controls are designed properly and are effective in the preparation of financial statements for external purposes in accordance with IFRS. The CEO and CFO are required to cause the Company to disclose any change in the Company’s ICOFR that occurred during the period beginning on October 1, 2012 and ending on December 31, 2012 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 are 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 makes substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves. 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 in, amongst other things, suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage, and the imposition of material fines and penalties.

Internationally, Canada is a signatory to the United Nations Framework Convention on Climate Change and previously ratified the Kyoto Protocol established thereunder, which set legally binding targets to reduce nation-wide emissions of carbon dioxide, methane, nitrous oxide, and other green-house gases (“GHGs”). The first commitment period under the Kyoto Protocol is the five year period from 2008-2012. In December 2011, the Canadian federal government announced that it would not agree to a second commitment period under the Kyoto Protocol after 2012. The federal government instead endorsed the Durban Platform, a broad agreement reached among the 194 countries that are party to the United Nations Framework Convention on Climate Change, during a conference held in Durban, South Africa in December 2011. The Durban Platform sets forth a process for negotiating a new climate change treaty that would create binding commitments for all major GHG emitters. The Canadian government expressed cautious optimism that agreement on a new treaty can be reached by 2015. The Durban Platform followed the Copenhagen Accord reached in December 2009 as government representatives met in Copenhagen, Denmark to negotiate a successor to the Kyoto Protocol. The Copenhagen Accord represents a broad political consensus and reinforces commitments to reducing GHG emissions but is not a binding international treaty. Although Canada had committed under the Copenhagen Accord to reduce its GHG emissions by 17% from 2005 levels by 2020, the target is not legally binding. As the details of the implementation of any federal legislation for GHGs that is applicable to the oil and gas industry have not been announced, the effect on Anderson’s operations cannot be determined at this time.

Additionally, regulation can take place at the provincial and municipal level. For example, Alberta introduced the Climate Change and Emissions Management Act, which provides a framework for managing GHG emissions and establishes a target of reducing specified gas emissions relative to gross domestic product to an amount that is equal to or less than 50% of 1990 levels by December 31, 2020. The accompanying regulations, the Specified Gas Emitters Regulation and the Specified Gas Emitters Reporting Regulation, require mandatory emissions reductions through the use of emissions intensity targets and impose duties to report.

The Government of Alberta implemented a new oil and gas royalty framework effective January 2009. The new framework, including subsequent amendments, established new royalties for conventional oil, natural gas and bitumen that are linked to price and production levels and apply to both new and existing conventional oil and gas activities and oil sands projects. Under the framework, the formula for conventional oil and natural gas royalties uses a sliding rate formula, dependent on the market price and production volumes. Royalty rates for conventional oil currently range from 0% to 40% and royalty rates for natural gas currently range from 5% to 36%. The Alberta Government has also introduced a number of royalty reduction and incentive programs to encourage oil and gas exploration and development in Alberta, including a new well royalty program, which has become a permanent feature of the royalty system, that provides a maximum 5% royalty rate for the first 12 months of production from new wells producing oil or natural gas to a maximum of 50,000 barrels of oil or 500 million cubic feet of natural gas. In addition, there is a 5% front end royalty rate for horizontal oil wells spud on or after May 1, 2010. Based on measured depth of the well, the 5% rate can be extended to 18 to 48 months on 50 Mstb to 100Mstb of oil production. The majority of the Company’s horizontal wells on Crown lands would qualify for 30 months of 5% royalty for up to 70Mstb of oil production.

BUSINESS PROSPECTS AND STRATEGY

The Company has 165 gross (90 net) sections of land and an inventory of 232 gross (148 net revenue) future drilling locations in the Cardium horizontal light oil play of which only 32% of net locations are recognized to date in the GLJ reserves report. With the completion of infrastructure projects in 2011, newly drilled Cardium horizontal wells can be easily connected to these gathering systems.

In addition to its Cardium light oil drilling inventory, the Company has identified an important new play on its lands – the Second White Specks. The Company has 104 gross (46 net) sections of Second White Specks (“2WS”) land and has assembled a drilling inventory of 102 gross (59 net) drilling locations. This zone is 100 meters deeper than the Cardium formation, is the oil-source zone for the Cardium play and is oil-charged with similar quality light oil that is in the Cardium formation. To date, other operators have drilled six horizontal oil wells offsetting the Company lands. The Company believes this play can be exploited by drilling off existing Cardium drilling pads and handling the Second White Specks oil and solution gas at the Company’s operated Cardium facilities.

The Company no longer considers itself to be a shallow gas production and development company. The Company is a light oil horizontal development company focused almost exclusively on the Cardium with a stacked resource play in the Second White Specks. The Company’s assets are almost entirely west of the fifth meridian (“W5M”), and a two hour drive north of Calgary on predominantly year-round access land. With a new reserves report, excellent drilling results yielding high initial productivity, relatively low capital costs and an expanded drilling inventory, the Company continues to explore its options through a strategic alternatives process. Anderson has prepared a confidential data room to assist in this process. Qualified parties have signed confidentiality agreements to review information in this data room.

With recent property dispositions and existing bank lines, the Company was able to complete all of its recently restructured drilling commitments. This winters drilling program has demonstrated significant initial production results for slick water frac stimulations that were vastly superior to previously announced techniques. The Company continues to add to its Cardium drilling inventory.

Subject to the outcome of the strategic alternatives process, Anderson will continue to focus on converting its asset base to be more than 50% oil and NGL production.

STRATEGIC ALTERNATIVES

The Company is continuing its 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 may include, but are not limited to, a sale of all or a material portion of the assets of Anderson, or a drilling joint venture, 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 discount to the value of the underlying assets, especially given its high quality light oil production base, prospective horizontal light 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 the 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.

Since January 1, 2012, Anderson has sold interests in 17 oil and natural gas properties for total consideration of $73.9 million, has restructured its shallow gas and Cardium horizontal drilling commitments, and has reduced its bank debt and working capital deficiency by 51% to $64.5 million. Total production sold was 2,292 BOED (71% natural gas), including 54 BOED of dry gas swapped in exchange for additional interests in Cardium drillable lands at Garrington, and is considered by the Company to be non-strategic. Anderson has sold almost its entire position west of the fourth meridian, exited the outside operated coal bed methane business and remains focused exclusively on its W5M 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 or the impact it will have on the Company’s financial position. The Company has not set a definitive schedule to complete the evaluation.

On April 1, 2012, the Company implemented a retention plan for its employees as part of this process, which was updated in October 2012 in conjunction with the lay-off of some of its staff.

QUARTERLY INFORMATION

The following table provides financial and operating results for the last eight quarters. Commodity prices remain volatile, affecting funds from operations and earnings throughout those quarters. In 2010, the Company changed its focus to oil projects in light of the continued depressed natural gas market, and suspended its shallow gas drilling program. Accordingly, revenues, funds from operations and earnings (loss) over the four quarters of 2011 reflect the benefits from increased sales of crude oil volumes resulting from the oil-focused drilling programs beginning in 2010. However, the Company curtailed its drilling program in 2012, drilling only 3 gross wells (2.45 net capital and revenue) in the first quarter of 2012 and 4 gross wells (4 net capital, 2.8 net revenue) in the last quarter of the year, versus the 51 gross (43.8 net capital, 38.7 net revenue) successful wells drilled in 2011. The natural declines and the impact of the sale of properties during 2012 contributed to production volume declines during each quarter of 2012. The reduction in production volumes and the declines in commodity prices relative to 2011 led to decreases in revenue during each quarter of 2012.

Also, earnings were affected in the fourth quarter of 2011 and the second quarter of 2012 by impairments in the value of property, plant and equipment related to the impact of natural gas prices on reserves values.

Bank loans plus cash working capital deficiency balances fluctuated in response to the capital spending programs related to the Cardium development through 2011 and 2012, and were drawn down with the proceeds from the sale of property, plant and equipment and cash from operating activities.

Total oil and gas sales and total revenue, net of royalties grew from 2010 to 2011 due to the focus on increasing oil production, as well as increased oil prices. However, total oil and gas sales and total revenue, net of royalties dropped significantly from 2011 to 2012 as a result of the decreased commodity prices, and also the sale of properties during 2012. Earnings before the effect of impairment in 2011 became losses in 2012, also primarily due to decreased commodity prices. Loss and loss per share were impacted by impairment charges triggered by decreases in natural gas and natural gas liquids prices in all three years ($20.0 million – 2012, $35.2 million – 2011, and $153.2 million – 2010.) These impairment charges and the dispositions reported in 2011 and 2012 have also reduced total assets. Approximately $73.9 million in proceeds from dispositions in 2012 and $11.6 million in 2011 were used to pay down bank debt.

Total debt including convertible debentures grew from 2010 to 2011, reflecting the financing related to the capital programs to develop oil properties.

ADDITIONAL INFORMATION

Additional information regarding Anderson and its business and operation, including its most recently filed annual information form is available on the Company’s profile on SEDAR at www.sedar.com. This information is also available on the Company’s website at www.andersonenergy.ca.

FORWARD-LOOKING STATEMENTS

Certain 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 operating netbacks; 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 continued development of the Company’s oil and gas assets are dependent, commodity price outlook and general economic outlook may constitute “forward-looking information” within the meaning of applicable securities legislation and necessarily involve risks and assumptions made by management of the Company including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation; loss of markets; volatility of commodity prices; currency fluctuations; imprecision of reserves estimates; environmental risks; competition from other producers; inability to retain drilling rigs and other services; adequate weather to conduct operations; sufficiency of budgeted capital, operating and other costs to carry out planned activities; wells not performing as expected; incorrect assessment of the value of acquisitions and farm-ins; failure to realize the anticipated benefits of acquisitions and farm-ins; 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.

CONVERSION

Disclosure 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.

Notes to the Consolidated Financial Statements

DECEMBER 31, 2012 AND DECEMBER 31, 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 2200, 333 – 7^th Avenue SW, Calgary, Alberta, Canada, T2P 2Z1.

The Company is continuing its 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 may include, but are not limited to, a sale of all or a material portion of the assets of Anderson, or a drilling joint venture, either in one transaction, or in a series of transactions, the outright sale of the Company, or a merger or other strategic transaction involving Anderson and a third party. The strategic review process is still ongoing and the Company will continue to identify, examine and consider a full range of strategic alternatives. Since January 1, 2012, the Company has sold approximately $74 million of oil and gas properties.

It is Anderson’s current intention to not disclose developments with respect to its strategic alternatives process unless and until the Board of Directors has approved a specific transaction or otherwise determines that disclosure is necessary in accordance with applicable law. The Company cautions that there are no assurances or guarantees that the process will result in a transaction or, if a transaction is undertaken, the terms or timing of such a transaction or the impact it will have on the Company’s financial position. The Company has not set a definitive schedule to complete the evaluation.

2. BASIS OF PREPARATION

(a) Statement of compliance. These consolidated financial statements comply with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”).

The consolidated financial statements were approved and authorized for issuance by the Board of Directors on March 15, 2013.

(b) Basis of measurement. The consolidated financial statements have been prepared on the historical cost basis except for derivative financial instruments, which are measured at fair value. The methods used to measure fair values are discussed in note 5.

(c) Functional and presentation currency. These consolidated financial statements are presented in Canadian dollars, which is the Company’s functional currency.

(d) Function and nature of expenses. Expenses in the consolidated statements of operations and comprehensive loss are presented as a combination of function and nature in conformity with industry practice. Transportation expenses, depletion and depreciation, and impairment of property, plant and equipment are presented in separate lines by their nature, while operating expenses and general and administrative expenses are presented on a functional basis. Significant operating and general and administrative expenses are presented by their nature in note 15.

3. SIGNIFICANT ACCOUNTING POLICIES

The accounting policies set out below have been applied consistently to all periods presented in these consolidated financial statements.

(a) Basis of consolidation:

(i) Subsidiaries. Subsidiaries are entities controlled by the Company. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases.

(ii) Jointly controlled operations and jointly controlled assets. Many of the Company’s oil and natural gas activities involve jointly controlled assets. The consolidated financial statements include the Company’s share of these jointly controlled assets and the proportionate share of the relevant revenue and related costs.

(iii) Transactions eliminated on consolidation. Intercompany balances and transactions, and any unrealized income and expenses arising from intercompany transactions, are eliminated in preparing the consolidated financial statements.

(b) Financial instruments:

(i) Non-derivative financial instruments. Non-derivative financial instruments comprise cash and cash equivalents, accounts receivable and accruals, accounts payables and accruals, bank loans and convertible debentures. Non-derivative financial instruments are recognized initially at fair value, plus, for instruments not classified as “fair value through profit or loss”, any directly attributable transaction costs. Subsequent to initial recognition, non-derivative financial instruments are measured as described below.

Cash and cash equivalents. Cash and cash equivalents comprise cash on hand, term deposits and other short-term highly liquid investments with original maturities of three months or less and are measured similar to other non-derivative financial instruments.

Other. Other non-derivative financial instruments, comprising accounts receivable and accruals, accounts payable and accruals, bank loans and convertible debentures, are measured at amortized cost using the effective interest method, less any impairment losses. The Company nets all transaction costs incurred in relation to the acquisition of a financial asset or liability, against the related financial asset or liability. Bank loans and convertible debentures are recorded net of issue costs and are presented net of deferred interest payments, with interest recognized in earnings on an effective interest basis.

(ii) Derivative financial instruments. The Company has entered into certain financial derivative contracts in order to manage the exposure to market risks from fluctuations in commodity prices. These instruments are not used for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, and thus has not applied hedge accounting, even though the Company considers all commodities contracts to be economic hedges. As a result, all financial derivative contracts are classified as “fair value through profit or loss” and are recorded on the statement of financial position at fair value. Transaction costs are recognized in profit or loss when incurred.

The Company accounts for forward physical delivery sales contracts, which are entered into and held for the purpose of delivery or receipt of non-financial items in accordance with expected sale or usage requirements as executory contracts. As such, these contracts are not considered to be derivative financial instruments and have not been recorded at fair value on the statement of financial position. Settlements on these physical sales contracts are recognized in oil and natural gas revenue.

Embedded derivatives are separated from the host contract and accounted for separately if the economic characteristics and risks of the host contract and the embedded derivative are not closely related. Changes in the fair value of separable embedded derivatives are recognized immediately in profit or loss.

(iii) Share capital. Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares and stock options are recognized as a deduction from equity, net of any tax effects.

(c) Property, plant and equipment:

Development and production costs. Items of property, plant and equipment, which include oil and gas development and production assets, are measured at cost less accumulated depletion and depreciation and accumulated impairment losses. All costs directly associated with the development of oil and natural gas reserves are recognized as oil and natural gas interests if they extend or enhance the recoverable reserves of the underlying assets. Such costs include property acquisitions, drilling and completion costs, gathering and processing infrastructure, capitalized decommissioning obligations, directly attributable internal costs and major overhaul and turnaround activities that maintain property, plant and equipment. Repairs and maintenance and operational costs that do not extend or enhance the recoverable reserves are charged to profit or loss when incurred.

Oil and natural gas assets are grouped into cash generating units (“CGUs”) for impairment testing. The Company had previously grouped its development and production assets into the following CGUs: Horizontal Oil, Deep Gas, Shallow Gas and Non-Core. In 2012, a significant portion of the assets in the Deep Gas and Non-core CGUs were sold and the remaining assets were regrouped into the following CGUs: Gas and Horizontal Cardium. The Horizontal Cardium CGU retained the same group of assets, but was renamed to better reflect the nature of those assets. The remaining assets in the Deep Gas and Non-core CGUs more closely resemble the operational, management and monitoring, product composition, and cash inflows of the assets within the Shallow Gas CGU. Accordingly, these remaining Deep Gas and Non-core assets have been grouped with the Shallow Gas assets to form the new Gas CGU.

When significant parts of an item of property, plant and equipment, including oil and natural gas interests, have different useful lives, they are accounted for as separate items (components).

Gains and losses on the sale of property, plant and equipment, including oil and natural gas interests, are determined by comparing the proceeds received to the carrying amount of property, plant and equipment and are recognized as a separate line item in other income. See note 14.

(d) Depletion and depreciation. The net carrying value of development or production assets is depleted using the unit of production method by reference to the ratio of production in the quarter to the related proved plus probable reserves, taking into account estimated future development and decommissioning costs necessary to bring those reserves into production. For other assets, depreciation is recognized in profit or loss over the estimated useful lives of each part of an item of property, plant and equipment using the declining balance method at rates between 20% and 30% per annum. Leased assets are depreciated over the shorter of the lease term and their useful lives unless it is reasonably certain that the Company will obtain ownership by the end of the lease term.

The costs of major overhaul and turnaround activities that are capitalized are depreciated on a straight-line basis over the period to the next recurrence of that set of activities, which varies from two to five years.

Depreciation methods, useful lives and residual values are reviewed at each reporting date.

(e) Impairment:

(i) Financial assets. A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of that asset.

An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate.

Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics.

All impairment losses are recognized in profit or loss.

An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. For financial assets measured at amortized cost the reversal is recognized in profit or loss.

(ii) Non-financial assets. The carrying amounts of the Company’s non-financial assets net of decommissioning liabilities, other than deferred tax assets are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists, then the asset’s recoverable amount is estimated.

For the purpose of impairment testing, assets are grouped together into CGUs; the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets. The recoverable amount of an asset or a CGU is the greater of its value in use (“VIU”) and its fair value less costs to sell (“FVLCTS”).

An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses are recognized in profit or loss. Impairment losses recognized in respect of CGUs are allocated first to reduce the carrying amount of any goodwill allocated to the units and then to reduce the carrying amounts of the other assets in the unit on a pro rata basis.

Impairment losses recognized in prior years are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation, if no impairment loss had been recognized.

(f) Share-based payments. The grant date fair value of equity-settled options granted to employees is recognized as share-based compensation expense, within general and administrative expenses, with a corresponding increase in contributed surplus over the vesting period. A forfeiture rate is estimated on the grant date and is adjusted to reflect the actual number of options that vest.

(g) Provisions. A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability. Provisions are not recognized for future operating losses.

Decommissioning obligations. The Company’s activities give rise to dismantling, decommissioning and site disturbance remediation activities. Provision is made for the estimated cost of site restoration and capitalized in the relevant asset category.

Decommissioning obligations are measured at the present value of management’s expectation of the expenditures required to settle the present obligation at the reporting date. Subsequent to the initial measurement, the obligation is adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation, including changes in the discount rate used to calculate the obligation. The increase in the provision due to the passage of time is recognized as finance costs whereas increases/decreases due to changes in the estimated future cash flows are capitalized. Actual costs incurred upon settlement of the decommissioning obligations are charged against the provision to the extent the provision was established, with any difference being recognized in profit or loss under gain or loss on sale of property, plant and equipment.

(h) Revenue. Revenue from the sale of oil and natural gas is recorded when the significant risks and rewards of ownership of the product is transferred to the buyer, which is usually when legal title passes to the external party. Oil and gas sales are presented before royalty obligations, whereas revenue is presented net of royalties.

Royalty income is recognized as it accrues in accordance with the terms of the overriding royalty agreements.

Fees charged to other entities for the use of pipelines, compressors and facilities owned by the Company are recognized as operating expense recoveries for use of transportation and processing assets when the usage is incurred.

Fees charged to other entities to recover overhead costs pursuant to capital and operating agreements are recognized as a reduction of general and administrative expenses in accordance with the terms of the capital and operating agreements.

(i) Transportation expenses. Transportation expenses include third-party pipeline and trucking costs incurred to transport oil, natural gas and natural gas liquids from processing and treating facilities to the point of sale.

(j) Finance income and expenses. Finance expenses comprise interest expense on borrowings, accretion of the discount on decommissioning obligations and accretion on convertible debentures recognized as financial liabilities.

Interest income is recognized as it accrues in profit or loss, using the effective interest method.

(k) Income tax. Income tax expense comprises current and deferred tax. Income tax expense is recognized in profit or loss except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity.

Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.

Deferred tax is recognized using the balance sheet method, providing for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination. In addition, deferred tax is not recognized for taxable temporary differences arising on the initial recognition of goodwill. Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, but they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously.

A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

(l) Earnings per share. Basic earnings per share is calculated by dividing the profit or loss attributable to common shareholders of the Company by the weighted average number of common shares outstanding during the period. Diluted earnings per share is determined by adjusting the profit or loss attributable to common shareholders and the weighted average number of common shares outstanding for the effects of dilutive instruments such as options granted to employees.

(m) New standards and interpretations not yet adopted: Standards that are issued but not yet effective and that the Company reasonably expects to be applicable at a future date are listed below.

IFRS 9 – Financial Instruments. IFRS 9, as issued, reflects the first phase of the IASB’s work on the replacement of IAS 39 and applies to classification and measurement of financial assets as defined in IAS 39. The standard is effective for annual periods beginning on or after January 1, 2015. In subsequent phases, the IASB will address classification and measurement of financial liabilities, hedge accounting and derecognition.

IFRS 10 – Consolidated Financial Statements. IFRS 10 requires an entity to consolidate an investee when it is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. IFRS 10 replaces SIC-12 Consolidation – Special Purpose Entities and parts of IAS 27 Consolidated and Separate Financial Statements. The standard is effective for annual periods beginning on or after January 1, 2013.

IFRS 11 – Joint Arrangements. IFRS 11 requires a venturer to classify its interest in a joint arrangement as a joint venture or a joint operation. Joint ventures will be accounted for using the equity method of accounting whereas for a joint operation the venturer will recognize its share of the assets, liabilities, revenue and expenses of the joint operation. IFRS 11 supersedes IAS 31 Interests in Joint Ventures and SIC-13 Jointly Controlled Entities – Non-Monetary Contributions by Venturers. The standard is effective for annual periods beginning on or after January 1, 2013.

IFRS 12 – Disclosure of Interests in Other Entities. IFRS 12 applies to entities that have an interest in a subsidiary, a joint arrangement, an associate or an unconsolidated structured entity. This standard is effective for annual period beginning on or after January 1, 2013.

IFRS 13 – Fair Value Measurements. IFRS 13 defines fair value, sets out in a single IFRS framework for measuring value and requires disclosure about fair value measurements. IFRS 13 applies to IFRSs that require or permit fair value measurements or disclosures about fair value measurement, except in specified circumstances. The standard is effective for annual periods beginning on or after January 1, 2013.

The Company has not completed its assessment of the impact of the above standards.

4. MANAGEMENT JUDGEMENTS AND ESTIMATES

The preparation of the consolidated financial statements in accordance with IFRS requires management to make judgements, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual results ultimately may differ from these estimates.

(a) Judgements. The key judgements made in applying accounting policies that have the most significant effect on the amounts recognized in these consolidated financial statements are as follows:

(i) Identification of cash generating units. Cash generating units are defined as the lowest grouping of integrated assets that generate identifiable cash inflows that are largely independent of the cash inflows of other assets or groups of assets. The classification of assets into cash generating units requires significant judgement and interpretations with respect to shared infrastructure, geographical proximity, petroleum type and similar exposure to market risk and materiality. The Company had previously grouped its development and production assets into the following CGUs: Horizontal Oil, Deep Gas, Shallow Gas and Non-Core. In 2012, the Deep Gas and Non-core assets have been grouped with the Shallow Gas assets to form the new Gas CGU. See note 3 (c) and note 7.

(ii) Fair value of derivatives. The fair value of financial instruments that are not traded in an active market is determined using valuation techniques. The Company uses its judgement to select a variety of methods and makes assumptions that are primarily based on market conditions existing at the end of each reporting period. The Company uses directly and indirectly observable inputs in measuring the value of financial instruments that are not traded in active markets, including quoted commodity prices and volatility. See note 19(d).

(b) Use of estimates. Information about assumptions and estimation uncertainties that have a significant risk of resulting in a material adjustment within the next financial year are as follows:

(i) Estimates of oil and natural gas reserves. Depletion and depreciation as well as the amounts used in impairment calculations are based on estimates of oil and natural gas reserves. Reserves estimates are based on engineering data, estimated future prices, expected future rates of production and the timing of future capital expenditures, all of which are subject to many uncertainties and interpretations. At least once per year, a reserves estimate is prepared by independent qualified reserves evaluators. The Company expects that, over time, its reserves estimates will be revised upward or downward based on updated information such as the results of future drilling, testing and production levels, and may be affected by changes in commodity prices. See notes 6 and 7.

(ii) Recoverable amounts of CGUs. The recoverable amount of a CGU used in the assessment of impairment is the greater of its VIU and its FVLCTS.

VIU is determined by estimating the present value of the future net cash flows from the continued use of the CGU, and is subject to the risks associated with estimating the value of reserves.

FVLCTS refers to the amount obtainable from the sale of a CGU in an arm’s length transaction between knowledgeable, willing parties, less costs of disposal. The criteria used in the estimation of this amount are discussed in note 5.

At December 31, 2012 the recoverable amounts of the Company’s CGUs were based on their estimated FVLCTS. Note 5 outlines the factors considered in estimating these amounts. The key assumptions and estimates of the value of oil and gas reserves and the existing and potential markets for the Company’s oil and gas assets are made at the time of reserves estimation and market assessment and are subject to change as new information becomes available. Changes in international and regional factors including supply and demand of commodities, inventory levels, drilling activity, currency exchange rates, weather, geopolitical and general economic environment factors may result in significant changes to the estimated recoverable amounts of CGUs. See note 7.

(iii) Decommissioning obligations. The total decommissioning obligation is estimated based on the Company’s net ownership interest in all wells and facilities, estimated costs to reclaim and abandon these wells and facilities and the estimated timing of the costs to be incurred in future years, based on current legal and constructive requirements and technology. The estimated obligations and actual costs may change significantly due to changes in regulations, technology, timing of the expenditure and the discount rates used to determine the net present value of the obligations. See note 10.

(iv) Deferred taxes. Deferred tax assets and liabilities are measured using enacted or substantively enacted tax rates at the reporting date in effect for the period in which the temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as part of the provision for income taxes in the period that includes the enactment date. The recognition of deferred tax assets is based on the assumption that it is probable that taxable profit will be available against which the deductible temporary differences can be utilized.

(v) Allowance for doubtful accounts. The Company maintains an allowance for doubtful accounts to provide for receivables which may ultimately be uncollectible. The allowance is determined in light of a number of factors including company specific conditions, economic events and the Company’s historical loss experience. The allowance is assessed quarterly by a detailed formal review of accounts receivable balances. See note 19(b).

(vi) Share-based compensation. The Company uses the Black-Scholes option pricing model in determining share-based compensation expense, which requires a number of assumptions to be made, including the risk-free interest rate, expected option life, forfeiture rate, and expected share price volatility. Consequently, the actual share-based compensation expense may vary from the amount estimated. See note 12.

Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the year in which the estimates are revised and in any future years affected.

5. DETERMINATION OF FAIR VALUE

A number of the Company’s accounting policies and disclosures require the determination of fair value, for both financial and non-financial assets and liabilities. Fair values have been determined for measurement and/or disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining fair values is disclosed in the notes specific to that asset or liability.

(a) Property, plant and equipment. Property, plant and equipment are recognized at fair value in a business combination. The fair value of property, plant and equipment is the estimated amount for which property, plant and equipment could be exchanged on the acquisition date between a willing buyer and a willing seller in an arm’s length transaction after proper marketing wherein the parties had each acted knowledgeably, prudently and without compulsion.

The Company estimated the FVLCTS to determine the recoverable amounts of the Company’s CGUs for impairment testing. The FVLCTS of each CGU was estimated based on consideration of the following:

(i) net present value of proved plus probable reserves using a pre-tax discount rate of 10% as determined by independent qualified reserves evaluators;

(ii) management’s estimate of the fair value of undeveloped land;

(iii) a review of the values indicated by the metrics of recent market transactions of similar assets within the oil and gas industry; and

(iv) management’s estimate of additional fair value from asset development not included in (i) above.

The market value of other items of property, plant and equipment is based on the quoted market prices for similar items.

(b) Cash and cash equivalents, accounts receivable and accruals and accounts payable and accruals. The fair value of cash and cash equivalents, accounts receivable and accruals and accounts payable and accruals is estimated as the present value of future cash flows, discounted at the market rate of interest at the reporting date. At December 31, 2012 and December 31, 2011, the fair value of these balances approximated their carrying value due to their short term to maturity.

(c) Bank loans. The fair value of bank loans approximates their carrying value, as they bear interest at floating rates and the premium charged at December 31, 2012 and December 31, 2011 was indicative by the Company’s current credit spreads.

(d) Derivatives. The fair value of forward contracts and swaps is derived from quoted prices received from financial institutions and is based on published forward price curves as at the measurement date, using the remaining contracted oil and natural gas volumes.

(e) Stock options. The fair value of employee stock options is measured using a Black-Scholes option pricing model. Measurement inputs include share price on measurement date, exercise price of the instrument, expected volatility (based on weighted average historic volatility adjusted for changes expected due to publicly available information), weighted average expected life of the instruments and forfeiture rate (both based on historical experience and general option holder behaviour), expected dividends, and the risk-free interest rate (based on government bonds).

The Company classified the fair value of its financial instruments measured at fair value according to the following hierarchy based on the amount of observable inputs used to value the instrument:

• Level 1 – observable inputs such as quoted prices in active markets;
• Level 2 – inputs, other than the quoted market prices in active markets, which are observable, either directly and/or indirectly; and
• Level 3 – unobservable inputs for the asset or liability in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

The fair value of the derivative contracts used for risk management as shown in the consolidated statements of financial position as at December 31, 2012 and December 2011 is measured using level 2.

During the years ended December 31, 2012 and 2011, there were no transfers between level 1, level 2 and level 3 classified assets and liabilities.

6. PROPERTY, PLANT AND EQUIPMENT

Cost or deemed cost

Capitalized overhead. For the year ended December 31, 2012, additions to property, plant and equipment included internal overhead costs of $3.4 million (December 31, 2011 – $4.6 million).

Depletion, depreciation and impairment charges. Depletion and depreciation, impairment of property, plant and equipment, and any reversal thereof, are recognized as separate line items in the consolidated statements of operations (see note 7). The Company included $145.3 million in future development costs and $4.5 million in abandonment costs related to undeveloped reserves (December 31, 2011 – $264.9 million, $11.0 million respectively).

Sale of property, plant and equipment. For the year ended December 31, 2012, the Company sold interests in 17 properties for total consideration of $73.9 million (December 31, 2011 – $11.6 million). See note 14.

7. IMPAIRMENT LOSS AND IMPAIRMENT REVERSAL

In 2011, there were indicators of impairment and reversal of impairment for the Deep Gas, Shallow Gas and Non-core CGUs due to changes in forecasted commodity prices used by the Company’s independent qualified reserves evaluators when compared to December 31, 2010. Accordingly, the Company tested those CGUs for impairment or reversal and determined that the aggregate carrying value of these CGUs was $35.2 million (net of impairment reversals of $9.7 million recorded for the Deep Gas CGU) higher than the recoverable amount and impairments were recorded ($2.6 million – Deep Gas CGU; $25.8 million – Shallow Gas CGU; and $6.8 million – Non-core CGU.)

The recoverable amounts of the CGUs were estimated based on the fair value less costs to sell (see notes 4 and 5). Carrying amounts are calculated as the net book value of property, plant and equipment less provisions for decommissioning obligations.

In 2012, declines in forecasted commodity prices were indicators of impairment. Forecasted commodity prices at December 31, 2012 declined between 14% and 18% for natural gas and between 4% and 16% for light, sweet crude oil 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 December 31, 2012 compared to December 31, 2011:

In the second quarter of 2012, the Company tested its gas-weighted CGUs for impairment and determined that the aggregate carrying value of these CGUs was $20 million higher than the recoverable amounts and impairments were recorded ($13 million for the Shallow Gas CGU and $7 million for the Deep Gas CGU). In the third and fourth quarters of 2012, the Company tested all of its CGUs for impairment and determined that no additional charges for impairment were required.

The carrying values recognized in each previous CGU are provided for illustration and comparison to the revised CGUs as follows:

(1) Carrying amounts exclude inventory and corporate assets of $1.5 million at December 31, 2011, and $1.6 million at December 31, 2012.

8. BANK LOANS

At December 31, 2012, total bank facilities were $65 million, consisting of a $55 million revolving term credit facility and a $10 million working capital credit facility with a syndicate of Canadian banks. The revolving term credit facility and the working capital credit facility have a maturity date of July 10, 2013, and all outstanding advances become repayable on July 10, 2013. Accordingly, on December 31, 2012, the bank loans have been classified as a current liability. Under the agreement, advances can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, bankers’ acceptance or LIBOR loan rates plus applicable margins. These margins vary from 3% to 4% depending on the borrowing option used. At December 31, 2012, no amounts were drawn in U.S. funds.

The average effective interest rate on advances under the facilities in 2012 was 4.7% (December 31, 2011 – 5.3%). The Company had $0.4 million in letters of credit outstanding at December 31, 2012 that reduce the amount of credit available to the Company.

Loans are secured by a floating charge debenture over all assets and guarantees by material subsidiaries.

The available lending limits of the facilities are scheduled to be reviewed on or before May 15, 2013 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 or terms of the available facilities will not be adjusted at the next review.

9. CONVERTIBLE DEBENTURES

On December 31, 2010, the Company issued $50 million of convertible unsecured subordinated debentures (the “Series A Debentures”) on a bought deal basis. The Series A Debentures have a face value of $1,000, bear interest at the rate of 7.5% per annum payable semi-annually in arrears on the last day of January and July of each year commencing on July 31, 2011 and mature on January 31, 2016 (the “Maturity Date”). The Series A Debentures are convertible at the holder’s option at a conversion price of $1.55 per common share (the “Conversion Price”), subject to adjustment in certain events. The Series A Debentures are not redeemable by the Company before January 31, 2014. On or after January 31, 2014 and prior to the Maturity Date, the Series A Debentures are redeemable at the Company’s option, in whole or in part, at a price equal to their principal amount plus accrued and unpaid interest if the weighted average trading price of the common shares on the Toronto Stock Exchange for the 20 consecutive trading days preceding the date on which the notice of redemption is given is not less than 125% of the Conversion Price. The Series A Debentures are listed and posted for trading on the TSX under the symbol “AXL.DB”.

On June 8, 2011, the Company issued $46 million of convertible unsecured subordinated debentures (the “Series B Debentures”) on a bought deal basis. The Series B Debentures have a face value of $1,000, bear interest at the rate of 7.25% per annum payable semi-annually in arrears on the last day of June and December of each year commencing on December 31, 2011 and mature on June 30, 2017 (“Maturity Date”). The Series B Debentures are convertible at the holder’s option at a conversion price of $1.70 per common share (the “Conversion Price”), subject to adjustment in certain events. The Series B Debentures are not redeemable by the Company before June 30, 2014. On and after June 30, 2014 and prior to June 30, 2016, the Series B Debentures are redeemable at the Company’s option, in whole or in part, at a price equal to their principal amount plus accrued and unpaid interest if the weighted average trading price of the common shares on the Toronto Stock Exchange for the 20 consecutive trading days preceding the date on which the notice of redemption is given is not less than 125% of the Conversion Price. On or after June 30, 2016 and prior to the Maturity Date, the Series B Debentures may be redeemed in whole or in part at the option of the Company on not more than 60 days and not less than 30 days prior notice at a price equal to their principal amount plus accrued and unpaid interest. The Series B Debentures are listed and posted for trading on the TSX under the symbol “AXL.DB.B”.

Both the Series A and the Series B Debentures were determined to be compound instruments. As the Series A and Series B Debentures are convertible into common shares, the liability and equity components are presented separately. The initial carrying amount of the financial liability is determined by discounting the stream of future payments of interest and principal. Using the residual method, the carrying amount of the conversion feature is the difference between the principal amount and the carrying value of the financial liability. The Series A and Series B Debentures, net of the equity component and issue costs are accreted using the effective interest rate method over the term of the Series A and Series B Debentures, such that the carrying amount of the financial liability will equal the $50 million and $46 million principal balance at maturity respectively.

The following table indicates the convertible debenture activities:

The 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 $46.5 million as at December 31, 2012 (December 31, 2011 – $62.8 million) based on an undiscounted inflation-adjusted total future liability of $55.8 million (December 31, 2011 – $80.8 million). These payments are expected to be made over the next 25 years with the majority of costs to be incurred between 2013 and 2030 (current portion estimated – $1.2 million). At December 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 1.0% to 2.5% (December 31, 2011 – 0.9% to 3.1%) depending on the estimated timing of the future obligation.

11. TAXES

The temporary differences that gave rise to the Company’s deferred income tax liabilities (assets) at December 31, 2012 and December 31, 2011 were as follows:

The Company has recognized a net deferred tax asset based on the independently evaluated reserves report as cash flows are expected to be sufficient to realize the deferred tax asset.

The provision for income taxes differs from the result that would have been obtained by applying the combined federal and provincial tax rates to the loss before income taxes. The difference results from the following items:

At December 31, 2012, the Company has loss carry forwards of approximately $153 million that will expire between 2025 and 2032. The Company expects to be able to fully utilize these losses. The statutory tax rate decreased to 25% in 2012 from 26.5% in 2011 as a result of tax legislation enacted in 2007.

A continuity of the net deferred income tax (asset) liability is detailed in the following tables:

12. SHARE CAPITAL

Authorized 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.

Elimination of deficit. On May 16, 2011, the Company’s shareholders approved the elimination of the Company’s consolidated deficit as at January 1, 2011, without reduction to the Company’s stated capital or paid up capital.

Stock options. The Company has an employee stock option plan under which employees, directors and consultants are eligible to purchase common shares of the Company. Options are granted using an exercise price of stock options equal to the weighted average trading price of the Company’s common shares for the five trading days prior to the date of the grant. Options have terms of either five or ten years and vest equally over a three year period starting on the first anniversary date of the grant. Changes in the number of options outstanding during the years ended December 31, 2012 and 2011 are as follows:

The weighted average common share price at the date of exercise for stock options exercised in 2011 was $1.20. There were no options exercised in 2012.

The fair value of the options was estimated using the Black-Scholes model with the following weighted average inputs:

This estimated forfeiture rate is adjusted to the actual forfeiture rate when each tranche vests. Share-based compensation of $0.8 million (December 31, 2011 – $1.0 million) was expensed during the year ended December 31, 2012. In addition, share-based compensation of $0.3 million (December 31, 2011 – $0.5 million) was capitalized during the year ended December 31, 2012.

13. LOSS PER SHARE

Basic and diluted loss per share were calculated as follows:

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 year ended December 31, 2012, 14,386,800 options (December 31, 2011 – 14,014,182 options) and 59,316,889 common shares reserved for convertible debentures (December 31, 2011 – 59,316,889) were excluded from calculating dilutive earnings as they were anti-dilutive.

14. SUPPLEMENTAL REVENUE AND EXPENSE RECOVERY INFORMATION

Revenues for all product sales and services and expense recoveries are as follows:

Major customers. The revenues derived from external customers who individually amounted to 10 per cent or more of the Company’s revenues are as follows: $31.6 million (December 31, 2011 – $nil), $13.7 million (December 31, 2011 – $33.9 million), $10.9 million (December 31, 2011 – $28.6 million), and $4.9 million (December 31, 2011 – $30.8 million).

15. EXPENSES BY NATURE

16. EMPLOYEE BENEFIT EXPENSES

General and administrative expenses include employee benefit expense as follows:

Employees include all staff and directors of the Company. Personnel expenses directly attributed to capital activities have been capitalized and included in property, plant and equipment.

17. FINANCE INCOME AND EXPENSES

18. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in non-cash working capital is comprised of:

19. FINANCIAL RISK MANAGEMENT

(a) Overview. The Company’s activities expose it to a variety of financial risks that arise as a result of its exploration, development, production, and financing activities such as:

• credit risk;
• liquidity risk; and
• market risk.

This note presents information about the Company’s exposure to each of the above risks, the Company’s objectives, policies and processes for measuring and managing risk, and the Company’s management of capital. Further quantitative disclosures are included throughout these consolidated financial statements.

The Board of Directors oversees management’s establishment and execution of the Company’s risk management framework. Management has implemented and monitors compliance with risk management policies. The Company’s risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company’s activities.

(b) Credit risk. Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from the Company’s receivables from joint venture partners and oil and natural gas customers. The maximum exposure to credit risk is as follows:

Accounts receivable and accruals. All of the Company’s operations are conducted in Canada. The Company’s exposure to credit risk is influenced mainly by the individual characteristics of each customer or joint venture partner.

A substantial portion of the Company’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. Receivables from oil and natural gas customers are normally collected on the 25th day of the month following the related sale of oil and gas production. The Company’s policy to mitigate credit risk associated with these balances is to establish commercial relationships with large customers. The Company historically has not experienced any significant collection issues with its oil and natural gas customers. Receivables from joint venture partners are typically collected within ninety days.

The Company attempts to mitigate the risk from joint venture receivables by obtaining venturer pre-approval of significant capital expenditures. However, the receivables are from participants in the oil and natural gas sector, and collection of the outstanding balances is dependent on industry factors such as commodity price fluctuations, escalating costs and the risk of unsuccessful drilling. In addition, further risk exists with joint venturers as disagreements occasionally arise that increase the potential for non-collection.

The Company does not typically obtain collateral from oil and natural gas customers or joint venturers; however, the Company does have the ability to withhold production from joint venturers in the event of non-payment.

The Company’s allowance for doubtful accounts as at December 31, 2012 was $0.9 million (December 31, 2011 – $0.9 million). This allowance was mostly created in prior years and is associated with prior corporate acquisitions and potential joint venture billing disputes.

The maximum exposure to credit risk for accounts receivable and accruals, net of allowance for doubtful accounts at the reporting date by type of customer was:

These amounts exclude offsetting amounts owing to joint venture partners that are included in accounts payable and accruals.

(c) Liquidity risk. Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due. The Company’s objective is to ensure, as far as possible, that it will always have sufficient liquidity to meet its liabilities when due, under both normal and stressed conditions, without incurring unacceptable losses or risking damage to the Company’s reputation.

To achieve this objective, the Company prepares annual capital expenditure budgets, which are regularly monitored and updated as considered necessary. The Company uses authorizations for expenditures on both operated and non operated projects to further manage capital expenditures. To provide capital when needed, the Company has revolving reserves-based credit facilities which are reviewed semi-annually by its lenders. These facilities are described in note 8. The Company also attempts to match its payment cycle with collection of oil and natural gas revenue on the 25th of each month.

The following are the contractual maturities of financial liabilities, including associated interest payments on convertible debentures and excluding the impact of netting agreements at December 31, 2012:

(d) Market risk. Market risk is the risk that changes in market prices, such as commodity prices, foreign exchange rates and interest rates will affect the Company’s income or the value of the financial instruments. The objective of market risk management is to manage and control market risk exposures within acceptable parameters, while optimizing the return.

The Company may use both financial derivatives and physical delivery sales contracts to manage market risks. All such transactions are conducted within risk management tolerances that are reviewed by the Board of Directors.

Currency risk. Prices for oil are determined in global markets and generally denominated in United States dollars. Natural gas prices obtained by the Company are influenced by both U.S. and Canadian demand and the corresponding North American supply, and recently, by imports of liquefied natural gas. The exchange rate effect cannot be quantified but generally an increase in the value of the Canadian dollar as compared to the U.S. dollar will reduce the prices received by the Company for its petroleum and natural gas sales.

There were no financial instruments denominated in U.S. dollars at December 31, 2012 or December 31, 2011.

Interest rate risk. Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The interest charged on the outstanding bank loans fluctuates with the interest rates posted by the lenders. The Company has not entered into any mitigating interest rate hedges or swaps, however the Company has $50 million and $46 million of convertible debentures with fixed interest rates of 7.5% and 7.25% respectively, maturing January 31, 2016 and June 30, 2017 (see note 9). Had the borrowing rate on bank loans been 100 basis points higher (or lower) throughout the year ended December 31, 2012, earnings would have been affected by $0.6 million (December 31, 2011 – $0.4 million) based on the average bank debt balance outstanding during the year.

Commodity price risk. Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for oil and natural gas are impacted by both the relationship between the Canadian and U.S. dollar and world economic events that dictate the levels of supply and demand.

It is the Company’s policy to economically hedge some oil and natural gas sales through the use of various financial derivative forward sales contracts and physical sales contracts. The Company does not apply hedge accounting for these contracts. The Company’s production is usually sold using “spot” or near term contracts, with prices fixed at the time of transfer of custody or on the basis of a monthly average market price. The Company, however, may give consideration in certain circumstances to the appropriateness of entering into long term, fixed price sales contracts. The Company does not enter into commodity contracts other than to meet the Company’s expected sale requirements.

At December 31, 2012 the following derivative contracts were outstanding and recorded at estimated fair value:

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 December 31, 2012, the Company estimates that it would pay $1.1 million to terminate these contracts.

The fair value of the financial commodity risk management contracts have been allocated to current and non-current liabilities on a contract by contract basis as follows:

The fair value of derivative contracts at December 31, 2012 would have been impacted as follows had the oil prices used to estimate the fair value changed by:

In July 2012, the Company entered into physical sales contracts to sell 7,000 GJ per day of natural gas between August 1, 2012 and September 30, 2012 at a weighted average AECO price of $2.45 per GJ. The Company realized $0.1 million of gains associated with these contracts.

(e) Capital management. Anderson’s capital management objective is to maintain a flexible capital structure that optimizes the cost of capital and maintains investor, creditor and market confidence while sustaining the future development of the business.

The Company manages its capital structure and makes adjustments to it in the light of changes in economic conditions and the risk characteristics of the underlying petroleum and natural gas assets. The Company’s capital structure includes shareholders’ equity of $133.0 million, bank loans of $48.1 million, convertible debentures with a face value of $96.0 million and the cash working capital deficiency of $16.4 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 including decommissioning expenditures). This ratio may increase at certain times as a result of acquisitions, the timing of capital expenditures and market conditions. In order to facilitate the management of this ratio, the Company prepares annual capital expenditure budgets, which are updated as necessary depending on varying factors including current and forecast crude oil and natural gas prices, capital deployment and general industry conditions. The annual and updated budgets are approved by the Board of Directors. 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 additional GAAP measures.

(1) Excludes unrealized gains (losses) on derivative contracts.

There were no changes in the Company’s approach to capital management during the year.

The high ratios reflect low natural gas prices, the capital expenditures and the convertible debenture financing required to make the transition from a gas-weighted company to an oil-weighted company. The 28 per cent decline in natural gas liquids prices and 17 per cent decline Canadian oil prices compared to the fourth quarter of 2011 have materially affected funds from operations and have increased the debt to funds from operations ratios. The impact on the net debt before convertible debentures ratio was mitigated by reducing bank debt with proceeds from dispositions during the year more so than the impact of the reduction of total net debt because there was not a proportionate reduction in the convertible debenture balances.

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.

20. RELATED PARTY TRANSACTIONS

Key management personnel are comprised of all officers and directors of the Company.

On June 8, 2011, the Company issued 1,575 Series B Convertible Debentures to key management personnel at a price of $1,000 per convertible debenture for total gross proceeds of $1.6 million as part of a $46.0 million bought deal offering of convertible debentures.

Compensation of key management personnel was as follows:

21. COMMITMENTS AND CONTINGENCIES

(a) 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 December 2012, the Company reached an agreement to terminate its previous commitment to drill 74 Edmonton Sand gas wells. In consideration for the termination of the commitment, the Company conveyed to the farmor a 25 per cent carried interest in four Cardium horizontal light oil wells. Three of the four wells were existing farm-in commitment wells to parties unrelated to the farmor. At December 31, 2012, one drilling commitment remained outstanding. This remaining commitment well was drilled in January 2013.

As at December 31, 2012, the Company also had commitments for future capital expenditures of $0.4 million that are expected to be incurred during the first quarter of 2013.

(b) Operating lease commitments. The Company leases various equipment, vehicles, and surface land locations under cancellable operating lease agreements. Surface lease arrangements may be cancelled at any time following reclamation of any site used in the Company’s operations. For equipment and vehicle leases, the Company may terminate the leases at any time, subject to certain immaterial conditions and guarantees.

The Company leases various offices and computer software under non-cancellable operating lease agreements. The head office lease terminates on June 30, 2014, while other lease terms are between one and three years, and the majority of lease agreements are renewable at the end of the lease period at the prevailing market rate.

The minimum future payments under non-cancellable operating leases are as follows:

The total operating lease expenditure charged to the income statement during the year is disclosed in note 15.

(c) Other commitments and contingencies. The Company has entered into firm service gas transportation agreements in which the Company guarantees 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:

The Company entered into a facilities construction and operation agreement in 2011 that defines the term based on a volume throughput at a specific fee per cubic metre of oil that utilizes the facility. The value of volume and fee amounts to $2.6 million (“Term Amount”). As at December 31, 2012 the Company has satisfied $1.6 million of the Term Amount. In addition, the agreement contains a guaranteed a five-year minimum annual volume and fee (“Minimum Revenue”) to the crude oil pipeline operator related to volumes of crude oil shipments through the new facilities and pipeline, reduced by actual volumes shipped. To date, the volumes of crude oil shipped has exceed the minimum required. If the Company exceeds the minimum volume requirement in a single year, the excess is carried forward as a credit to the Minimum Revenue guarantee in the subsequent year. Subsequent to December 31, 2012, the Company exceeded the cumulative five year minimum volume requirement, thereby eliminating the yearly Minimum Revenue requirement.

Corporate Information

Head Office

2200, 333 – 7th Avenue, S.W.

Calgary, Alberta

Canada T2P 2Z1

Phone (403) 262-6307

Fax (403) 261-2792

Website http://www.andersonenergy.ca/

Directors

J.C. Anderson(4)

Calgary, Alberta

Brian H. Dau

Calgary, Alberta

Christopher L. Fong (1)(2)(3)(4)

Calgary, Alberta

Glenn D. Hockley (1)(3)(4)

Calgary, Alberta

David J. Sandmeyer (2)(3)(4)

Calgary, Alberta

David G. Scobie (1)(2)(4)

Calgary, Alberta

Member of:

(1) Audit Committee

(2) Compensation & Corporate

Governance Committee

(3) Reserves Committee

(4) Special Committee

Auditors

KPMG LLP

Independent Engineers

GLJ Petroleum Consultants Ltd.

Legal Counsel

Bennett Jones LLP

Registrar & Transfer Agent

Valiant Trust Company

Stock Exchange

The Toronto Stock Exchange

Symbol AXL, AXL.DB, AXL.DB.B

Contact Information

Anderson Energy Ltd.

Brian H. Dau

President & Chief Executive Officer

(403) 262-6307

info@andersonenergy.ca

Officers

J.C. Anderson

Chairman of the Board

Brian H. Dau

President & Chief Executive Officer

David M. Spyker

Chief Operating Officer

M. Darlene Wong

Vice President Finance, Chief Financial

Officer & Secretary

Blaine M. Chicoine

Vice President, Drilling and Completions

Sandra M. Drinnan

Vice President, Land

Philip A. Harvey

Vice President, Exploitation

Jamie A. Marshall

Vice President, Exploration

Patrick M. O’Rourke

Vice President, Production

Abbreviations used

AECO – intra-Alberta Nova inventory transfer price bbl – barrel

bpd – barrels per day

Mstb – thousand stock tank barrels

Mbbls – thousand barrels

BOE – barrels of oil equivalent

BOED – barrels of oil equivalent per day

BOPD – barrels of oil per day

MBOE – thousand barrels of oil equivalent

MMBOE – million barrels of oil equivalent

m3 – cubic meters

GJ – gigajoule

Mcf – thousand cubic feet

Mcfd – thousand cubic feet per day

MMcf – million cubic feet

MMcfd – million cubic feet per day

MMBtu – million British thermal units

NGL – natural gas liquids

WTI – West Texas Intermediate

US – United States dollars

Contact Information
Anderson Energy Ltd.
Brian H. Dau
President & Chief Executive Officer
(403) 262-6307
info@andersonenergy.ca
www.andersonenergy.ca