Anderson Energy Ltd.
TSX : AXL

Anderson Energy Ltd.

November 15, 2011 07:47 ET

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

CALGARY, ALBERTA--(Marketwire - Nov. 15, 2011) - Anderson Energy Ltd. ("Anderson" or the "Company") (TSX:AXL) is pleased to announce its operating and financial results for the three and nine months ended September 30, 2011.

HIGHLIGHTS


--  Funds from operations in the third quarter were $12.7 million, up 61%
    from the third quarter of 2010. Earnings were $7.5 million in the third
    quarter of 2011.
--  Total production was 7,351 BOED in the third quarter of 2011 compared to
    7,292 BOED in the third quarter of 2010.
--  Oil and NGL production averaged 2,345 bpd in the third quarter, up 76%
    from the prior year. Oil represented 1,709 bpd of total production and
    was 201% higher than last year.
--  GLJ Petroleum Consultants ("GLJ") have completed an interim reserves
    report of all of the Company's oil and natural gas properties effective
    October 1, 2011. Proved plus probable ("P&P") BOE reserves have
    increased 13% from December 31, 2010 to 35.8 MMBOE.
--  P&P reserves replacement was 650% for oil and 571% for oil and NGL. On a
    BOE basis, Anderson replaced 297% of production with P&P reserves in the
    first nine months of 2011.
--  In the last nine months, Anderson increased proved developed producing
    ("PDP"), total proved ("TP") and P&P oil reserves by 72%, 28% and 62%
    respectively through Cardium drilling.
--  Cardium P&P reserves more than doubled to 9.9 MMBOE representing 28% of
    total P&P reserves volumes and 46% of total P&P reserves value on a pre-
    tax 10% net present value ("NPV 10") basis. The Company's net asset
    value is estimated to be $1.56 per share.
--  Anderson achieved a 23% reduction in drilling and completion costs in
    the Garrington and Willesden Green operating areas in the third quarter,
    making the average cost to drill and complete a well $2.3 million. To
    date in the fourth quarter of 2011, Anderson's drilling and completion
    costs in the Garrington field have been $2.1 million per well.
--  Anderson announced a new Cardium light oil discovery in Ferrier on
    October 26, 2011, confirming an extension to the Ferrier Cardium G Oil
    Pool. By year end, a total of four wells are expected to be drilled in
    Ferrier.
--  Capitalizing on the oil drilling success in the third quarter, the 2011
    capital program has been increased to $145 million allowing for
    acceleration of capital spending that was originally planned for the
    first quarter of 2012. Anderson now expects to drill 36% more net wells
    than previously planned in 2011 and the net benefit is expected to be
    more oil production and cash flow from operations in 2012.

FINANCIAL AND OPERATING HIGHLIGHTS

(thousands of
 dollars, unless          Three months ended           Nine months ended
 otherwise stated)         September 30                September 30
                                              %                           %
                          2011   2010(i) Change       2011   2010(i) Change
Oil and gas
 sales(ii)          $   28,513 $  18,928    51%  $  85,665 $  62,511    37%
Revenue, net of
 royalties(ii)      $   24,970 $  17,263    45%  $  76,029 $  55,756    36%

Funds from
 operations         $   12,655 $   7,876    61%  $  37,467 $  27,234    38%
Funds from
 operations per
 share
  Basic and diluted $     0.07 $    0.05    40%  $    0.22 $    0.16    38%

Earnings (loss)
 before effect of
 impairment or
 reversals thereof  $    6,667 $ (3,057)   318%  $   8,918 $ (5,251)   270%
Earnings (loss) per
 share before
 effect of
 impairment or
 reversals thereof
  Basic and diluted $     0.04 $  (0.02)   300%  $    0.05 $  (0.03)   267%
Earnings (loss)     $    7,472 $(39,029)   119%  $   9,723 $(88,242)   111%
Earnings (loss) per
 share
  Basic and diluted $     0.04 $  (0.23)   117%  $    0.06 $  (0.52)   112%

Capital
 expenditures,
 including
 acquisitions net
 of dispositions    $   49,713 $  39,378    26%  $ 118,351 $  85,269    39%

Bank loans plus
 cash working
 capital deficiency                              $ 108,583 $ 102,198     6%
Convertible
 debentures                                      $  84,334 $       -   100%

Shareholders'
 equity                                          $ 195,251 $ 215,389    (9%)

Average shares
 outstanding
 (thousands):
  Basic                172,550   172,400      -    172,534   169,569     2%
  Diluted              172,550   172,400      -    173,040   169,569     2%
Ending shares
 outstanding
 (thousands)                                       172,550   172,400      -

Average daily
 sales:
  Natural gas
   (Mcfd)               30,038    35,778   (16%)    31,972    36,668   (13%)
  Oil (bpd)              1,709       568   201%      1,615       469   244%
  NGL (bpd)                636       761   (16%)       667       762   (12%)
  Barrels of oil
   equivalent
   (BOED)                7,351     7,292     1%      7,610     7,342     4%
Average prices:
  Natural gas
   ($/Mcf)          $     3.85 $    3.43    12%  $    3.74 $    4.12    (9%)
  Oil ($/bbl)       $    89.05 $   68.24    30%  $   91.59 $   70.77    29%
  NGL ($/bbl)       $    66.07 $   51.41    29%  $   68.76 $   53.89    28%
  Barrels of oil
   equivalent
   ($/BOE)(ii)      $    42.16 $   28.21    49%  $   41.23 $   31.19    32%
Realized gain
 (loss) on
 derivative
 contracts ($/BOE)  $     1.29 $       -   100%  $  (0.17) $       -  (100%)
Royalties ($/BOE)   $     5.24 $    2.48   111%  $    4.64 $    3.37    38%
Operating costs
 ($/BOE)            $    11.22 $    9.45    19%  $   11.30 $    9.96    13%
Transportation
 costs ($/BOE)      $     0.89 $    0.26   242%  $    0.63 $    0.19   232%
Operating netback
 ($/BOE)            $    26.10 $   16.02    63%  $   24.49 $   17.67    39%

Wells drilled
 (gross)                    21        14    50%         41        43    (5%)

(i) 2010 results have been restated to conform to International Financial
Reporting Standards.

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

OPERATIONS

Cardium Horizontal Oil Drilling. In the third quarter of 2011, Anderson drilled 21 gross (18.0 net capital, 16.4 net revenue) Cardium horizontal oil wells. From May 1, 2010 to September 30, 2011, the Company has drilled 62 gross (50.4 net capital, 45.6 net revenue) wells and placed 58 gross (42.6 net revenue) Cardium oil wells on production. The Company plans to drill 51 gross (44.3 net capital, 39.1 net revenue) Cardium horizontal oil wells in 2011, which is 36% higher than previous estimates on a net revenue basis.

Cardium Horizontal Oil Capital Costs. Anderson has been diligently reducing its drilling and completion costs with the application of new technology and other cost savings measures. Third quarter 2011 drilling and completion costs in the Garrington and Willesden Green areas are approximately 23% lower than those encountered in the first half of the year even with longer horizontal well lengths and additional fracture stimulation ("frac") stages.


Garrington/Willesden Green Capital Costs:
Period                                                   Average
                                                        Drilling
                                                             and
                                 Average     Average  Completion   Number of
                          Drilling Costs  Completion       Costs Frac Stages
                                   ($MM) Costs ($MM)       ($MM)    per Well
2010                                 1.6         1.4         3.0          13
First half of 2011                   1.8         1.2         3.0          17
Third quarter 2011                   1.4         0.9         2.3          19
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To date in the fourth quarter of 2011, Anderson's drilling and completion costs in the Garrington field have been $2.1 million per well.

In the third quarter of 2011, the Company experimented with alternative completion technology to the commonly used open hole casing packer multi-stage fracture stimulation technology. The Company sees considerable benefits in addition to lower costs from the application of this technology. Anderson plans to utilize this technology in the Willesden Green, Garrington and Ferrier fields for its future Cardium horizontal oil wells.

Ferrier Horizontal Cardium Oil Discovery. On October 26, 2011, Anderson announced a new Cardium light oil discovery in Ferrier with an extension to the Ferrier Cardium G oil pool. To date, one operated horizontal oil well and one outside operated horizontal oil well have been drilled. The Company owns or controls 13.8 gross (6.8 net) sections of land in the Ferrier area, with most of the land being a contiguous land block in Twp 37, Ranges 7 and 8 W5M. Based on in-house mapping, the Company estimates it has 30 gross (15.9 net) locations remaining to be drilled in Ferrier. A production tank battery and solution gas compressor have been built to handle the initial production from its operated lands. Two additional appraisal wells are planned to be drilled during the fourth quarter.

Garrington Cardium Oil Pool Update. Anderson has identified a northern extension to its core Garrington field. Recent performance of wells drilled in the northern portion of the Garrington area have been above the average Garrington type curve. The Garrington battery consolidation project was completed in early August, with all of the Company's single well batteries connected to the central 15-34 tank battery. This project is expected to reduce operating and capital costs in this area. The 100% owned facility was connected by Plains Midstream Canada to the Rangeland Pipeline system on October 24, 2011. This facility is expected to process third party volumes and could represent an attractive source of processing fee income for Anderson.

Garrington represented 59% of the Company's oil production in the third quarter of 2011. The Company is completing is reservoir computer simulation study to design a waterflood in the Garrington field.

Cardium Land and Drilling Inventory. Anderson's Cardium prospective land inventory is 124.5 gross (74.0 net) sections, an increase of 23% over December 31, 2010. Approximately 85% of the Company's Cardium lands are located in the oil prone fairway and the balance is in the gas prone fairway. Using geological mapping and offset production information, the Company has high-graded a location list to drill in the oil prone fairway. The list includes 204 gross (129.8 net) horizontal locations to be drilled in the next few years (including wells drilled to date). Each location is a development location that is technically feasible and not contingent upon the drilling of other wells.

Other Horizontal Oil Opportunities. The Company has identified five non-Cardium zones on its lands in central Alberta, with potential for horizontal oil drilling with multi-stage fracture stimulation, which is similar technology as used in Cardium horizontal drilling. These zones are Second White Specs, Belly River, Viking, Glauconite and Mannville. Anderson has 50.8 gross (29.1 net) sections of land in the emerging Second White Specs horizontal oil play. The Company is currently evaluating the timeline and level of participation to drill these horizons in 2012.

Edmonton Sands Farm-In. Anderson announced a 200 well Edmonton Sands farm-in commitment on January 29, 2009 and drilled 126 wells in the winter of 2009/2010. The Company was planning to drill the remaining 74 wells during the upcoming winter. The terms of the farm-in agreement have been modified to extend the commitment date to March 31, 2013. With weak natural gas prices, it has been decided to defer drilling the remaining 74 wells until after 2012.

RESERVES

GLJ, an independent reserves evaluator, has completed an interim reserves report of all of the Company's oil and natural gas properties effective October 1, 2011, prepared in accordance with procedures and standards contained in the Canadian Oil and Gas Evaluation ("COGE") Handbook. The reserves definitions used in preparing the interim report are those contained in the COGE Handbook and the Canadian Securities Administrators National Instrument 51-101. This is not a year end reserves report. The October 1, 2011 report is the first step in the process and will be updated by GLJ for year end reserves reporting. As of October 1, 2011, the Company has 12.4 MMBOE PDP (30% oil and NGL), 19.5 MMBOE TP (23% oil and NGL) and 35.8 MMBOE P&P (27% oil and NGL) reserves. The price forecast used in the evaluation is shown in Management's Discussion and Analysis for the three and nine months ended September 30, 2011.

P&P reserves replacement was 650% for oil and 571% for oil and NGL. On a BOE basis, Anderson replaced 297% of production with P&P reserves in the first nine months of 2011. The Company's P&P BOE reserves increased 13% since December 31, 2010.

P&P reserves from the Cardium drilling program are 9.9 MMBOE at October 1, 2011, more than double the 4.7 MMBOE at December 31, 2010. Cardium reserves represent 28% of total P&P reserves volumes and 46% of total P&P reserves value on a pre-tax NPV 10 basis.

Since the inception of the Cardium play 18 months ago and including production, the Company has added 10.5 MMBOE of P&P reserves with its Cardium drilling program.


SUMMARY OF OIL AND GAS RESERVES
                                                 October 1, 2011
                                                                     Pre-tax
                                         Oil     NGL     Gas   Total NPV 10
                                     (Mbbls) (Mbbls)  (MMcf)  (MBOE)    ($M)
Proved developed producing             2,242   1,460  52,069  12,379 207,113
Proved developed producing and
 proved developed non-producing        2,375   1,512  59,213  13,755 219,933
Total proved                           2,840   1,703  89,842  19,517 227,772
Proved plus probable                   6,334   3,185 157,525  35,773 349,575
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SUMMARY OF OIL AND GAS RESERVES
                                                December 31, 2010
                                                                     Pre-tax
                                         Oil     NGL     Gas   Total NPV 10
                                     (Mbbls) (Mbbls)  (MMcf)  (MBOE)    ($M)
Proved developed producing             1,303   1,376  52,498  11,428 166,058
Proved developed producing and
 proved developed non-producing        1,471   1,426  59,955  12,889 175,619
Total proved                           2,226   1,673  97,313  20,117 184,248
Proved plus probable                   3,908   2,676 150,621  31,687 271,469
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Oil now represents 18% of the Company's PDP, 15% of TP and 18% of P&P reserves as compared to 11%, 11% and 12% respectively at December 31, 2010. Anderson increased PDP, TP and P&P oil reserves by 72%, 28% and 62%, respectively, in the previous nine months.


NET ASSET VALUATION(1)
As at September 30, 2011

($ millions, unless otherwise stated)
P&P reserves (pre-tax NPV 10)                                     $    350
Undeveloped land (excluding Cardium horizontal prospective lands)        5
Cardium horizontal prospective lands (2)                               118
Unrealized hedging gains and stock option proceeds                      18
Bank loans plus cash working capital deficiency                       (109)
Series B convertible debentures                                        (46)
                                                                   -------
Net asset value estimate, September 30, 2011 (1)                  $    336
Net asset value estimate per fully diluted share, September 30,
 2011 (3,4)                                                       $   1.56
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(1) The net asset valuation ("NAV") shows what the Company's reserves would
be produced at using GLJ's October 1, 2011 price forecast and costs. The
value is a snapshot in time and based on various assumptions including
commodity prices that vary over time. It should not be assumed that NAV
represents the fair market value of Anderson shares. GLJ's price forecast at
October 1, 2011 for the period 2012 to 2017 is an average of $0.57 per Mcf
lower than at January 1, 2011, which negatively impacted NPV 10 by 
approximately $30 million.

(2) Cardium undeveloped land valued at $2.5 million per net section not
booked in the interim GLJ reserves report assuming $2.4 million NPV 10 per
net location drilled over a three year time span (49.4 net unbooked
locations).

(3)For the purposes of this calculation at September 30, 2011, it was
assumed that the Series B convertible debentures (convertible at $1.70 per
share) would remain as debt and the Series A convertible debentures would be
converted at $1.55 per share and the outstanding shares were adjusted
accordingly.

(4) Based on 215.1 million outstanding shares on a fully diluted basis.

The NAV per share calculation discussed above does not include any upside associated with the Company's extensive land holdings prospective for horizontal oil in the Second White Specs, Viking, Belly River, Mannville and Glauconite zones. It also does not include any incremental value associated with the Company's shallow gas drilling inventory in a more supportive natural gas price environment.

PRODUCTION

During the third quarter of 2011, the Company averaged 7,351 BOED, with oil and NGL volumes representing 32% of total volumes. Oil and NGL production for the three months ended September 30, 2011 was 2,345 bpd, up substantially from 1,329 bpd in the third quarter of 2010. Of this, 1,709 bpd or 73% is crude oil production, compared to 568 bpd or 43% in the third quarter of 2010. The Company's production in the third quarter of 2011 was negatively impacted by plant outages and a slow start to the third quarter drilling program caused by wet ground conditions. The Company also sold non-core heavy oil properties in the third quarter of 2011. Anderson estimates that production in the fourth quarter of 2011 could reach 8,200 BOED with oil and NGL production representing approximately 43% of total production. The Company estimates that 2011 total production will be at the mid point of its previously stated guidance of 7,500 to 8,000 BOED.

Anderson estimates that oil and NGL production will average approximately 45% of total production in 2012 and that the Company will likely achieve the significant milestone of a balanced production profile sometime during the next twelve months.

FINANCIAL RESULTS

Capital expenditures were $49.7 million (net of proceeds on dispositions of $6.2 million) in the third quarter of 2011 with $43.7 million spent on drilling and completions and $11.4 million spent on facilities. This compares to capital expenditures of $39.4 million in the third quarter of 2010.

Anderson's funds from operations were $12.7 million in the third quarter of 2011 compared to $7.9 million in the third quarter of 2010. The Company's average crude oil and natural gas liquids sales prices in the third quarter of 2011 were $89.05 and $66.07 per barrel compared to $68.24 and $51.41 respectively per barrel in the third quarter of 2010. The Company has entered into fixed price oil swaps for 2011 and 2012. The Company's unrealized gain on its oil hedge was $11.2 million for the nine months ended September 30, 2011. The Company's average natural gas sales price was $3.85 per Mcf in the third quarter of 2011 compared to $3.43 per Mcf in third quarter of 2010 and included a $0.8 million gain relation to physical fixed price sales contracts. The Company recorded earnings of $7.5 million in the third quarter of 2011 primarily due to the oil hedging gains, a stronger contribution to total revenue by additional oil volumes and higher oil and NGL prices. The Company's operating netback was $26.10 per BOE in the third quarter of 2011 compared to $16.02 per BOE in the third quarter of 2010. The increase in the operating netback was primarily due to the increase in oil and NGL prices and oil volumes. Anderson's field net operating income for its Cardium horizontal properties in the first nine months of 2011 was $63.78 per BOE as compared to $14.01 per BOE for the remainder of its properties (exclusive of hedging).


                                 Average
                                wellhead
                             natural gas               Operating  Funds from
                                   price     Revenue     netback  operations
                                 ($/Mcf)     ($/BOE)     ($/BOE)     ($/BOE)
2009 (i)                            3.95       27.74       15.07       11.26
2010 (i)                            3.96       31.31       17.44       13.22
First quarter of 2011               3.58       36.80       21.96       15.63
Second quarter of 2011              3.79       44.71       25.47       19.75
Third quarter of 2011               3.85       42.16       26.10       18.71
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First quarter of 2012
 estimate
($90 to $100 WTI
 Canadian(ii) plus oil hedge     3.75 to    53.00 to    36.00 to    27.00 to
 program)                       4.00(ii)       56.00       39.00       30.00
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(i) 2009 results have not been restated to conform to International
Financial Reporting Standards. 2010 results have been restated to conform to
International Financial Reporting Standards.

(ii) Estimate

As Anderson increases its oil production, its revenue per BOE, operating netback per BOE and funds from operations per BOE should increase and contribute to profitability in 2012. Royalties were $5.24 per BOE in the third quarter of 2011 compared to $5.37 per BOE in the second quarter of 2011. Operating expenses in the third quarter of 2011 were $11.22 per BOE, which was 7% lower than the second quarter of 2011. The second quarter of 2011 was affected by costs associated with temporary production facilities and wet weather.

2011 CAPITAL PROGRAM

During the third quarter of 2011, the Company's Board of Directors approved an increase in the capital program to $145 million, net of dispositions, to focus on the development of new Cardium oil discoveries and required facility infrastructure for new discoveries in Ferrier, Willesden Green and Garrington North. In addition, the Company will be evaluating with the drill-bit a potentially new core area for Cardium oil development in the Northwest Pembina/Carrot Creek areas. A portion of the capital budget increase is an acceleration of planned 2012 capital spending into 2011. The benefit of the acceleration is expected to be increased oil production and funds from operations in 2012. In 2011, the Company estimates it could drill up to 51 gross (44.3 net capital, 39.1 net revenue) Cardium horizontal oil wells, which is 36% higher on a net revenue basis than previous estimates.

COMMODITY CONTRACTS

Crude Oil. As part of its price management strategy, Anderson has entered into fixed price swap contracts based on the NYMEX crude oil price in Canadian dollars. The average for volumes and prices for these contracts is summarized below:


                                                                    Weighted
                                                     Weighted    average WTI
                                                average volume      Canadian
Period                                                   (bpd)       ($/bbl)
October 1, 2011 to December 31, 2011                     1,500         94.18
January 1, 2012 to March 31, 2012                        1,500        104.63
April 1, 2012 to December 31, 2012                       1,000        103.93
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The Company entered into the hedging contracts to protect its capital program and support its bank borrowing base. As the Company continues to grow its oil production, it will evaluate the merits of additional commodity hedging as part of a price management strategy.

The mark to market value of the hedging contracts at September 30, 2011 was $9.2 million.

Natural Gas. The Company has physically contracted to sell 15,000 GJ per day of natural gas at an average Canadian dollar AECO price of $4.06 per GJ, from July 1, 2011 to October 31, 2011. This equates to approximately 13.9 MMcfd at an average plant gate price of approximately $4.15 per Mcf. The Company recorded a $0.8 million gain, included in oil and gas sales in relation to these physical contracts.

STRATEGY

With oil prices at or near present levels, the Company expects to be able to finance the foreseeable drilling program out of cash flow and currently available credit facilities, without the need for external financing. Anderson estimates its oil and NGL production will grow from 18% of total production in 2010 to 34% in 2011 to potentially 45% in 2012. Independent analysts currently estimate that funds from operations could range from $48 million to $59 million in 2011 and $72 million to $95 million in 2012, which is significant growth when compared to $36.5 million in funds from operations in 2010. Management believes that a strategy of cash flow growth through light oil horizontal drilling is the best solution in this period of anemic natural gas prices. As part of this transition from natural gas to oil, Anderson completed two convertible debenture financings with five to six year terms and conversion prices of $1.55 and $1.70 per common share. This provides the Company with better financial flexibility to make the transformation to a balanced oil and gas producer. Debt leverage is higher than some of its peers in 2011; however, with improving revenue from oil production in 2011 and 2012, leverage is expected to return to more typical levels for junior oil producers by the end of 2012. The Company believes it has the depth of prospects to stay the oil course and still bring forward natural gas prospects for drilling when economic conditions dictate. In a stronger natural gas market, the Company has a significant shallow gas inventory of over 850 gross locations that can be drilled. This asset is strategic and valuable to the Company longer term.

Anderson will closely monitor commodity prices and adjust its capital spending plans appropriately to stay within bank lines. The Company is planning to divest of various non-core oil and natural gas properties outside of its Central Alberta core area and use the proceeds from the disposition to reduce bank debt and/or expand its Cardium oil drilling program.

Over the last year, the Company has been able to move up the learning curve in the Cardium play with drilling, completion and production initiatives. Anderson is very focused on increasing its land position in the Cardium and utilizing new technologies to lower costs and enhance well performance.

OUTLOOK

Oil prices continue to be strong, but volatile, and are expected to remain so in the near term. Natural gas prices are weak and the timing of natural gas price recovery to economic levels is uncertain. Anderson will continue to dedicate its capital program to light oil horizontal oil drilling as these prospects represent the best economics.

By the end of 2011, Anderson estimates it will have 54.5 net revenue Cardium horizontal wells on production, up 28% from the end of the third quarter 2011. The Company has increased its Cardium development drilling inventory by 52% since December 31, 2010 and is becoming an industry leader in lowering Cardium per well capital costs, including a 23% reduction in the third quarter of 2011. Anderson believes it is well positioned in the play and the results from the Cardium program will help to peel the natural gas label off the stock price and reward shareholders with more of an oil company valuation. As oil production grows in 2011 and 2012, the impact that this higher priced commodity will have on its cash flow and earnings could be significant.

Anderson's strategy of diversification into light oil drilling is now showing the benefits. Edmonton benchmark light oil prices continue to remain strong despite recent volatility in WTI Canadian oil prices. Anderson estimates that oil and NGL production could average 45% of total production in 2012 and that sometime in 2012, the Company could have a balanced production portfolio of oil and natural gas.

For more information, we encourage investors to review our website at www.andersonenergy.ca.

Brian H. Dau, President & Chief Executive Officer

November 15, 2011

Management's Discussion and Analysis

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2011 AND 2010

The following discussion and analysis of financial results should be read in conjunction with the unaudited interim consolidated financial statements of Anderson Energy Ltd. ("Anderson" or the "Company") for the three and nine months ended September 30, 2011, the unaudited interim consolidated financial statements for the three months ended March 31, 2011 and the audited consolidated financial statements and management's discussion and analysis ("MD&A") of Anderson for the years ended December 31, 2010 and 2009 and is based on information available as of November 14, 2011.

The following information is based on the unaudited interim consolidated financial statements of the Company at September 30, 2011, as prepared by management. The financial data included in this interim MD&A is in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB") and interpretations of the International Financial Reporting Interpretations Committee ("IFRIC") that are expected to be effective or available for early adoption by the Company as at December 31, 2011, the date of the Company's first annual reporting under IFRS. The effective date of the transition to IFRS was January 1, 2010. The transition to IFRS has been reflected by restating previously reported financial statements for 2010. Previously, the Company's financial statements were prepared under Canadian generally accepted accounting principles ("CGAAP"). The adoption of IFRS does not impact the underlying economics of the Company's operations or its cash flows. Note 17 to the interim consolidated financial statements for the three months ended March 31, 2011 and note 16 to the interim consolidated financial statements for the three and nine months ended September 30, 2011 contain detailed descriptions of the Company's adoption of IFRS, including reconciliations of the consolidated financial statements previously prepared under CGAAP to those under IFRS.

Production and reserves numbers are stated before deducting Crown or lessor royalties.

Included in the discussion and analysis are references to terms commonly used in the oil and gas industry such as funds from operations, finding, development and acquisition ("FD&A") costs, operating netback and barrels of oil equivalent ("BOE"). Funds from operations as used in this report represent cash from operating activities before changes in non-cash working capital and decommissioning expenditures. See "Review of Financial Results - Funds from Operations" for details of this calculation. Funds from operations represent both an indicator of the Company's performance and a funding source for on-going operations. FD&A costs measure the cost of reserves additions and are an indicator of the efficiency of capital expended in the period. Operating netback is calculated as oil and gas revenues less royalties, operating expenses and transportation expenses and is a measure of the profitability of operations before administrative and financing expenditures. Production volumes and reserves are commonly expressed on a BOE basis whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil and natural gas measurement units into one basis for improved analysis of results and comparisons with other industry participants. These terms are not defined by IFRS or CGAAP and therefore are referred to as non-GAAP measures.

All references to dollar values are to Canadian dollars unless otherwise stated.

The abbreviations used in this discussion and analysis are located on the last page of this document.

REVIEW OF FINANCIAL RESULTS

Overview. For the three months ended September 30, 2011, funds from operations were $12.7 million, up 61% from the third quarter of 2010, even though sales volumes on a BOE basis were similar to the prior year, due to the Company's refocus on Cardium light oil drilling. Sales volumes for the three months ended September 30, 2011 averaged 7,351 BOED, which was 5% lower than the second quarter of 2011, mostly due to a reduction in gas sales volumes as discussed below.

Capital additions, net of proceeds from dispositions were $49.7 million for the three months ended September 30, 2011. During the third quarter of 2011, the Company drilled 21 gross (18.0 net capital, 16.4 net revenue) Cardium light oil wells with a 100% success rate. The Company also tied in 17 gross (13.4 net revenue) Cardium light oil wells in the third quarter of 2011.

Bank loans plus cash working capital deficiency were $108.6 million at September 30, 2011. On June 8, 2011, the Company completed a convertible subordinated debenture financing for proceeds, net of commission and expenses, of $43.9 million. Proceeds were initially used to pay down bank debt. The availability created in the credit facilities, along with cash flows, will be used to help finance the Company's 2011 and 2012 capital programs.

Revenue and Production. In 2010, the Company changed its focus to oil prospects in light of the continued depressed natural gas market. During the third quarter of 2011, oil and natural gas liquids revenue represented 63% of total revenue compared to 38% for the third quarter of 2010.

The Company suspended its shallow gas drilling program after the first quarter of 2010 until natural gas prices improve. Accordingly, natural production declines were not replaced, resulting in the following decreases in gas sales. Gas sales volumes for the three months ended September 30, 2011 decreased to 30.0 MMcfd from 32.0 MMcfd in the second quarter of 2011 and 35.8 MMcfd in the same period in 2010. Gas sales for the nine months ended September 30, 2011 were 32.0 MMcfd compared to 36.7 MMcfd for the nine months ended September 30, 2010.

Oil sales for the three months ended September 30, 2011 averaged 1,709 bpd compared to 1,759 bpd in the second quarter of 2011 and 568 bpd for the third quarter of 2010. The decrease in volumes from the second quarter of 2011 is primarily due to the sale of heavy oil properties in the third quarter of 2011.

Natural gas liquids sales for the three months ended September 30, 2011 averaged 636 bpd compared to 667 bpd in the second quarter of 2011 and 761 bpd for the third quarter of 2010. Natural gas liquids volumes were affected by natural declines, consistent with declines in gas production.

The following tables outline production revenue, volumes and average sales prices for the periods ended September 30, 2011 and 2010.


OIL AND NATURAL GAS REVENUE
                             Three months ended        Nine months ended
                                September 30              September 30
(thousands of dollars)           2011         2010         2011         2010
Natural gas              $      9,834 $     11,304 $     31,788 $     39,984
Gain on fixed price
 natural gas contracts            818            -          818        1,302
Oil(1)                         14,002        3,567       40,377        9,061
NGL                             3,863        3,598       12,517       11,213
Royalty and other                  (4)         459          165          951
                          ------------------------  ------------------------
Total                    $     28,513 $     18,928 $     85,665 $     62,511
----------------------------------------------------------------------------

(1) The three month numbers exclude the realized and unrealized gains on
derivative contracts of $0.9 million and $6.4 million respectively during
the three months ended September 30, 2011 (September 30, 2010 - $Nil). The
nine month numbers exclude the realized loss and unrealized gain on
derivative contracts of $0.4 million and $11.2 million respectively during
the nine months ended September 30, 2011 (September 30, 2010 - $Nil).


PRODUCTION
                                  Three months ended       Nine months ended
                                        September 30            September 30
                                    2011        2010        2011        2010
Natural gas (Mcfd)                30,038      35,778      31,972      36,668
Oil (bpd)                          1,709         568       1,615         469
NGL (bpd)                            636         761         667         762
                            ------------------------------------------------
Total (BOED)                       7,351       7,292       7,610       7,342
----------------------------------------------------------------------------


PRICES
                                Three months ended         Nine months ended
                                      September 30              September 30
                                 2011         2010         2011         2010
Natural gas ($/Mcf)(1)   $       3.85 $       3.43 $       3.74 $       4.12
Oil ($/bbl)(2)                  89.05        68.24        91.59        70.77
NGL ($/bbl)                     66.07        51.41        68.76        53.89
                          ------------------------  ------------------------
Total ($/BOE)(2,3)       $      42.16 $      28.21 $      41.23 $      31.19
----------------------------------------------------------------------------

(1) Price includes gain on fixed price natural gas contracts from the first
quarter of 2010 and the third quarter of 2011.

(2) The three month numbers exclude the realized and unrealized gains on
derivative contracts of $0.9 million and $6.4 million respectively during
the three months ended September 30, 2011 (September 30, 2010 - $Nil). The
nine month numbers exclude the realized loss and unrealized gain on
derivative contracts of $0.4 million and $11.2 million respectively during
the nine months ended September 30, 2011 (September 30, 2010 - $Nil).

(3) Includes royalty and other income classified with oil and gas sales.

Anderson's average natural gas sales price was $3.85 per Mcf for the three months ended September 30, 2011, 2% higher than the second quarter of 2011 price of $3.79 per Mcf and 12% higher than the third quarter of 2010 price of $3.43 per Mcf. Anderson's average gas sales price was $3.74 per Mcf for the nine months ended September 30, 2011, compared to $4.12 per Mcf in the comparable 2010 period. The natural gas price includes a gain of $0.8 million (September 30, 2010 - $1.3 million) on the Company's fixed price natural gas contracts. The gas price before the gain was $3.64 per Mcf in the first nine months of 2011 (September 2010 - $3.99 per Mcf). Gas prices remain depressed as a result of increased supply of natural gas in the United States.

Historically, Anderson has sold most of its gas at Alberta spot market prices. The Company is currently selling all of its unhedged gas production at the average daily index price. The Company has classified transportation costs as an offset to gas sales revenue as title transfers prior to transport on the applicable sales pipelines and transportation is being held by and charged by the gas purchasers. The Company has arranged firm service transportation agreements covering approximately 23 MMcfd of natural gas sales for various terms expiring in one to nine years.

Oil prices for the third quarter of 2011 have decreased 10% from the second quarter of 2011, but are 30% higher when compared to the same period in 2010. Oil prices continue to remain strong compared to 2010, but are also volatile in response to various geopolitical events.

Commodity Contracts. At September 30, 2011 the following derivative contracts summarized on a quarterly basis were outstanding and recorded at estimated fair value:


                                                                    Weighted
                                                     Weighted    average WTI
                                                average volume     Canadian
Period                                                   (bpd)       ($/bbl)
October 1, 2011 to December 31, 2011                     1,500         94.18
January 1, 2012 to March 31, 2012                        1,500        104.63
April 1, 2012 to December 31, 2012                       1,000        103.93
----------------------------------------------------------------------------

In 2011, these contracts had the following impact on the consolidated statements of operations and comprehensive loss:


                               Three months ended         Nine months ended
                                    September 30,              September 30,
(thousands of dollars)          2011         2010         2011          2010
Realized gain (loss) on
 derivative contracts   $        871 $          - $       (353) $          -
Unrealized gain on
 derivative contracts          6,350            -       11,166             -
                         ------------------------  -------------------------
                        $      7,221 $          - $     10,813  $          -
----------------------------------------------------------------------------

In June 2011, as part of its risk management program, the Company entered into fixed price natural gas contracts to manage commodity price risk. The Company entered into physical contracts to sell 15,000 GJ per day of natural gas from July 1, 2011 to October 31, 2011 at an average AECO price of $4.06 per GJ. The Company does not mark-to-market physical sales contracts as they are not considered to be derivative instruments. These contracts will affect the price of the commodity sold during the period of the contract. The Company recognized a gain of $0.8 million on these contracts during the three and nine months ended September, 2011.

Royalties. Royalties were 12.4% of revenue for the three months ended September 30, 2011 compared to 12.0% for the second quarter of 2011 and 8.8% for the three months ended September 30, 2010. The slight increase in the royalty rate from the second quarter is the result of more non-Crown wells coming on-stream with higher royalty rates. The Company received less gas cost allowance ("GCA") in the third quarter of 2011 compared to the same quarter of the previous year due to the decreased capital expenditures in natural gas related projects starting in 2010.

Royalties as a percentage of revenue are highly sensitive to prices and adjustments to GCA and so royalty rates can fluctuate from quarter to quarter. In addition, when prices and corresponding revenues are lower, fixed monthly GCA becomes more significant to the overall royalty rate. Under the Alberta government's New Royalty Framework, producers will pay a reduced Crown royalty rate of 5% for the first year on up to 500 MMcf of gas production or up to 50 Mstb of oil production. In addition, for horizontal oil wells, based on the measured depth of the well, the Company will pay the Crown a 5% royalty for 24 to 30 months for up to 60 to 70 Mstb of oil production. The majority of the Company's horizontal program on Crown lands would qualify for the 30 months of 5% royalty for up to 70 Mstb of oil production.


                                Three months ended        Nine months ended
                                      September 30              September 30
                                 2011         2010         2011         2010
Gross Crown royalties           10.3%        12.0%         9.6%        13.0%
Gas cost allowance             (5.5%)       (8.9%)       (5.3%)       (8.5%)
Other royalties                  7.6%         5.7%         6.9%         6.3%
                         ------------------------- -------------------------
Royalties                       12.4%         8.8%        11.2%        10.8%
Royalties ($/BOE)       $        5.24$        2.48$        4.64$        3.37
----------------------------------------------------------------------------

Operating Expenses. Operating expenses are generally higher for oil projects when compared to gas projects. Accordingly, the increases in operating expenses noted below are largely due to increased oil production and decreased lower cost gas production per BOE.

Operating expenses were $11.22 per BOE for the three months ended September 30, 2011 compared to $12.04 per BOE in the second quarter of 2011 and $9.45 per BOE in the third quarter of 2010. Operating expenses were $11.30 per BOE for the nine months ended September 30, 2011 compared to $9.96 per BOE in the first nine months of 2010. Operating expenses in the second quarter of 2011 were adversely affected by costs associated with temporary production and wet weather. The additional operating costs related to temporary oil production were mitigated in the third quarter of 2011 as these facilities were permanently connected to the new Garrington battery consolidation project and to a permanent battery installation in Willesden Green.

Transportation Expenses. Transportation expenses were $0.89 per BOE for the three months ended September 30, 2011 compared to $0.66 per BOE in the second quarter of 2011 and $0.26 per BOE in the third quarter of 2010. Actual transportation costs for the first and second quarters of 2011 exceeded the amounts previously estimated by approximately $0.2 million. This excess was recorded in the third quarter of 2011, contributing approximately $0.25 per BOE to the reported expenses. Transportation expenses were $0.63 per BOE for the nine months ended September 30, 2011 compared to $0.19 per BOE in the first nine months of 2010. The increase in transportation expenses in 2011 relative to 2010 is the result of more clean oil trucking charges associated with higher 2011 oil production. In the first nine months of 2011, oil production was 21% of total production compared with 6% in the first nine months of 2010.


OPERATING NETBACK

(thousands of                Three months ended           Nine months ended
 dollars)                          September 30                September 30
                             2011          2010          2011          2010
Revenue(1)          $      28,513 $      18,928 $      85,665 $      62,511
Realized gain (loss)
 on derivative
 contracts                    871             -          (353)            -
Royalties                  (3,543)       (1,665)       (9,636)       (6,755)
Operating expenses         (7,590)       (6,343)      (23,473)      (19,962)
Transportation
 expenses                    (602)         (172)       (1,304)         (387)
                     --------------------------  --------------------------
                    $      17,649 $      10,748 $      50,899 $      35,407
---------------------------------------------------------------------------
Sales (MBOE)                676.3         670.9       2,077.6       2,004.5
Per BOE
  Revenue(1)        $       42.16 $       28.21 $       41.23 $       31.19
  Realized gain
   (loss) on
   derivative
   contracts                 1.29             -         (0.17)            -
  Royalties                 (5.24)        (2.48)        (4.64)        (3.37)
  Operating expenses       (11.22)        (9.45)       (11.30)        (9.96)
  Transportation
   expenses                 (0.89)        (0.26)        (0.63)        (0.19)
                     --------------------------  --------------------------
                    $       26.10 $       16.02 $       24.49 $       17.67
---------------------------------------------------------------------------

(1) Includes royalty and other income classified with oil and gas sales.
Excludes unrealized gain on derivative contracts of $6.4 million and $11.2
million pertaining to fixed price crude oil swaps for the three and nine
months ended September 30, 2011 respectively (September 30, 2010 - $Nil).

General and Administrative Expenses. General and administrative expenses, excluding stock-based compensation, were $2.6 million or $3.81 per BOE for the three months ended September 30, 2011 compared to $2.0 million or $2.86 per BOE in the second quarter of 2011 and $2.0 million or $3.05 per BOE for the third quarter of 2010. General and administrative expenses, excluding stock-based compensation, were $7.2 million or $3.48 per BOE for the nine months ended September 30, 2011 compared to $6.0 million or $2.99 per BOE for the first nine months of 2010. General and administrative expenses increased in the third quarter of 2011 compared to the second quarter of 2011 as the result of a reduction in the amount of general and administrative expense capitalized. Gross general and administrative expenses increased for the nine months ended September 30, 2011 over 2010 due to increased salaries and bonus costs in 2011. Under IFRS, general and administrative expenses include share-based payments on the consolidated statement of operations and comprehensive income. IFRS also requires that the capitalization of general and administrative costs be limited to directly attributable costs. Capitalized general and administrative costs are limited to salaries and associated office rent of staff involved in capital activities. Under CGAAP, a reasonable allocation of general and administrative costs to property, plant and equipment was acceptable. As a result of the change in the capitalization criteria under IFRS, the Company increased its general and administrative costs by $0.1 million for the three months ended September 30, 2010 and by $0.4 million for the nine month ended September 30, 2010. The Company expects to have modestly higher general and administrative expenses in the future due to the adoption of IFRS.


                             Three months ended          Nine months ended
                                  September 30,               September 30,
(thousands of                              2010                        2010
 dollars)                    2011    (restated)          2011    (restated)
General and
 administrative
 (gross)            $       3,747 $       3,347 $      11,440 $       9,660
Overhead recoveries          (502)         (412)       (1,312)       (1,181)
Capitalized                  (671)         (892)       (2,895)       (2,488)
                     --------------------------  --------------------------
General and
 administrative
 (cash)             $       2,574 $       2,043 $       7,233 $       5,991
Net stock-based
 compensation                 239           382           730           785
                     --------------------------  --------------------------
General and
 administrative
 (net)              $       2,813 $       2,425 $       7,963 $       6,776
---------------------------------------------------------------------------
  General and
   administrative
   (cash) ($/BOE)   $        3.81 $        3.05 $        3.48 $        2.99
% Capitalized                 18%           27%           25%           26%
---------------------------------------------------------------------------

Stock-Based Compensation. The Company accounts for stock-based compensation plans using the fair value method of accounting. Stock-based compensation costs were $0.4 million for the third quarter of 2011 ($0.2 million net of amounts capitalized) compared to $0.4 million in the second quarter of 2011 ($0.3 million net of amounts capitalized) and $0.5 million ($0.4 million net of amounts capitalized) in the third quarter of 2010. Stock-based compensation costs were $1.2 million for the first nine months of 2011 ($0.7 million net of amounts capitalized) versus $1.2 million ($0.8 million net of amounts capitalized) in the first nine months of 2010.

Finance Expenses. Under IFRS, finance expenses include accretion on decommissioning obligations, accretion and interest on convertible debentures, as well as interest on bank loans. Previously under CGAAP, accretion on decommissioning obligations was included with depletion, depreciation and accretion. Finance expenses were $3.3 million for the third quarter of 2011, compared to $2.8 million in the second quarter of 2011 and $1.3 million in the third quarter of 2010. Finance expenses were $8.5 million for the nine months ended September 30, 2011, compared to $3.5 million in the comparable period of 2010. The increase in finance expenses from 2010 is the result of higher interest and accretion on the $96 million (principal) of convertible debentures issued on December 31, 2010 and June 8, 2011 at 7.5% and 7.25% respectively, and higher effective interest rates on bank loans, partially offset by lower average bank loan balances. There were no convertible debentures outstanding at September 30, 2010. The average effective interest rate on outstanding bank loans was 5.7% for the nine months ended September 30, 2011 compared to 4.9% for the comparable period in 2010.


                              Three months ended          Nine months ended
                                   September 30,               September 30,
(thousands of                               2010                        2010
 dollars)                     2011    (restated)          2011    (restated)
Interest and
 accretion on
 convertible
 debentures          $       2,233 $           - $       4,831 $           -
Interest expense on
 credit facilities
 and other                     670           836         2,394         2,254
Accretion on
 decommissioning
 obligations                   439           417         1,295         1,231
                      --------------------------  --------------------------
Finance expenses     $       3,342 $       1,253 $       8,520 $       3,485
----------------------------------------------------------------------------

Depletion and Depreciation. Depletion and depreciation was $12.3 million ($18.16 per BOE) for the third quarter of 2011 compared to $13.3 million ($18.90 per BOE) in the second quarter of 2011 and $10.6 million ($15.85 per BOE) in the third quarter of 2010. Depletion and depreciation was $38.0 million ($18.28 per BOE) for the first nine months of 2011 compared $32.4 million ($16.19 per BOE) for the comparable period in 2010. Decreased production in the third quarter of 2011 resulted in lower depletion and depreciation expense when compared to the second quarter of 2011.

Impairment of property, plant and equipment. Under CGAAP, impairment of property, plant and equipment was assessed on the basis of an asset's estimated undiscounted future cash flows compared with the asset's carrying amount and if impairment was indicated, discounted cash flows were prepared to quantify the amount of the impairment. Under IFRS, impairment is assessed based on discounted cash flows compared with the asset's carrying amount to determine the recoverable amount and measure the amount of the impairment. In addition, under IFRS, the Company is required to perform its test at a cash generating unit ("CGU") level, which is the smallest identifiable grouping of assets that generates largely independent cash inflows. CGAAP impairment was based on undiscounted cash flows on a full cost centre basis. There is no requirement under IFRS to test for impairment at least annually as was done under CGAAP. Instead, IFRS requires that when there are indicators of impairment present, that an impairment test be performed. In addition, under IFRS, the Company must evaluate whether there are any changes in circumstances that would support an impairment reversal, which was not allowable under CGAAP. This may result in recoveries of previous impairments in future periods, net of depletion and depreciation.

At January 1, 2010, the effective transition date to IFRS, the Company elected to use the IFRS 1 deemed cost exemption whereby the costs under CGAAP were allocated to CGUs based on reserves volumes and then tested for impairment. As a result, the Company recognized an impairment of $67.2 million at January 1, 2010 in the Shallow Gas CGU with a corresponding reduction in opening retained earnings. For the nine months ended September 30, 2010 and the year ended December 31, 2010 the Company recognized additional impairments of $111.0 million and $153.2 million respectively with a corresponding reduction in property, plant and equipment for the Shallow Gas, Deep Gas and Non-core CGUs due to declines in the future price forecasts used by the Company's independent qualified reserves evaluators for natural gas prices.

At September 30, 2011, there were significant changes in the future commodity prices forecasts used by the Company's independent qualified reserves evaluators when compared to December 31, 2010. The Company considered the downward price adjustments on natural gas to be an indicator of impairment for the Company's Shallow Gas and Non-Core CGUs. Similarly, the Company considered the upward price adjustments on natural gas liquids to be an indicator of impairment reversal for its Deep Gas CGU as a result of this CGU having a significant amount of natural gas liquids. All of the Company's oil and gas reserves were evaluated and reported on by independent qualified reserves evaluators at September 30, 2011. Based on this assessment, the Company determined that its Shallow Gas and Non-Core CGUs were impaired by $3.2 million and $5.4 million respectively and that $9.7 million of previous impairments were reversed from its Deep Gas CGU as a result of this CGU having a significant amount of natural gas liquids. Under CGAAP, no impairments were recognized in prior periods.

Decommissioning obligations. In the third quarter of 2011, the Company recorded an increase in decommissioning obligations of $6.8 million net of dispositions.

Under IFRS, the decommissioning obligations are measured as the best estimate of the expenditure to be incurred and require that the decommissioning obligations be re-measured at the end of each reporting period using period-end discount rates. The risk-free discount rates used by the Company to re-measure the obligations at the end of the third quarter were reduced by between 0.67% and 1.41% depending on the timelines to reclamation as a result of changes in the Canadian bond market. The re-measurement of the obligation at the end of the third quarter of 2011 resulted in a $6.2 million increase to decommissioning obligations with an offsetting adjustment to property, plant and equipment.

The Company also recorded $1.3 million in additional decommissioning obligations relating to current drilling activity and reduced decommissioning obligations by $1.0 million related to a property disposition in the third quarter of 2011. Accretion expense of $0.4 million for the third quarter of 2011 compared to $0.4 million in the second quarter of 2011 and $0.4 million in the third quarter of 2010 and was included in finance expenses.

Income Taxes. Anderson is not currently taxable. The Company does not anticipate paying current income tax in 2011. The Company has approximately $473 million in tax pools at September 30, 2011.

Funds from Operations. Funds from operations for the third quarter of 2011 were $12.7 million ($0.07 per share), 61% higher than the $7.9 million ($0.05 per share) recorded in the same period of 2010. This compares to funds from operations in the second quarter of 2011 of $13.9 million ($0.08 per share). Funds from operations for the first nine months of 2011 were $37.5 million ($0.22 per share) compared to $27.2 million ($0.16 per share) recorded in the same period of 2010. The increase in funds from operations in 2011 is a result of the Company's focus on oil prospects, which generate more funds from operations per BOE when compared to natural gas properties at current pricing. As new crude oil production is brought on-stream at higher expected operating margins, funds from operations are expected to increase. The changes in funds from operations as reported under IFRS for the three and nine months ended September 30, 2010 relate to the decrease in the capitalized general and administrative costs of $0.1 million and $0.4 million respectively from what was previously reported under CGAAP.


                               Three months ended        Nine months ended
                                     September 30              September 30
                                             2010                      2010
(thousands of dollars)           2011  (restated)         2011   (restated)
Cash from operating
 activities              $     11,893$      8,287 $     37,847 $     29,844
Changes in non-cash
 working capital                  701        (823)        (483)      (4,041)
Decommissioning
 expenditures                      61         412          103        1,431
                          -----------------------  ------------------------
Funds from operations    $     12,655$      7,876 $     37,467 $     27,234
---------------------------------------------------------------------------

Earnings (loss). The Company reported earnings of $7.5 million in the third quarter of 2011 compared to earnings of $5.9 million for the second quarter of 2011 and a loss of $39.0 million for the third quarter of 2010. The Company reported earnings of $9.7 million in the first nine months of 2011 compared to a loss of $88.2 million in the comparable period in 2010. Earnings in the third quarter of 2011 are a result of the unrealized gain on derivative contracts along with increased oil production combined with higher oil and NGL prices. The 2010 three month loss was due to a $48.3 million impairment recorded in the period, while the 2010 nine month loss was due to a $111.0 million impairment recorded in the period.

The Company's funds from operations and earnings are highly sensitive to changes in factors that are beyond its control. An estimate of the Company's sensitivities to changes in commodity prices, exchange rates and interest rates is summarized below:


SENSITIVITIES
                               Funds from Operations                Earnings
(thousands of dollars)          Millions   Per Share    Millions   Per Share
$0.50/Mcf in price of
 natural gas                 $       5.4 $      0.03 $       4.0 $      0.02
US $5.00/bbl in the WTI
 crude price                 $       3.1 $      0.02 $       2.3 $      0.01
US $0.01 in the US/Cdn
 exchange rate               $       1.0 $      0.01 $       0.7 $      0.00
1% in short-term interest
 rate                        $       0.5 $      0.00 $       0.4 $      0.00
----------------------------------------------------------------------------

This sensitivity analysis was calculated by applying different pricing, interest rate and exchange rate assumptions to the actual results for the twelve months ended September 30, 2011 related to production, prices excluding the impact of derivative contracts, royalty rates, operating costs and capital spending. As the Company changes its focus to crude oil development, the impact of oil prices is expected to become more significant and the impact of natural gas prices is expected to become less significant to funds from operations and earnings than is shown in the table above.

CAPITAL EXPENDITURES

The Company spent $49.7 million on capital additions, net of proceeds on dispositions in the third quarter of 2011. The breakdown of expenditures is shown below:


                                 Three months ended       Nine months ended
                                       September 30             September 30
                                               2010                     2010
(thousands of dollars)             2011  (restated)         2011  (restated)
Land, geological and
 geophysical costs         $        201$         28 $      3,967$        625
Acquisitions                          -         705            -       1,438
Proceeds on disposition          (6,203)       (192)     (11,570)    (2,399)
Drilling, completion and
 recompletion                    43,700      30,548       95,260      53,537
Drilling incentive credits         (262)     (1,003)        (400)    (3,617)
Facilities and well
 equipment                       11,436       7,910       28,001      33,782
Capitalized G&A                     671         892        2,895       2,488
                            -----------------------  -----------------------
Total finding, development
 & acquisition
expenditures                     49,543      38,888      118,153      85,854
  Change in compressor and
   other equipment
   inventory                        128         480          128       (644)
Office equipment and
 furniture                           42          10           70          59
                            -----------------------  -----------------------
Total net cash capital
 expenditures              $     49,713$     39,378 $    118,351$     85,269
----------------------------------------------------------------------------

Drilling statistics are shown below:


                                  Three months ended       Nine months ended
                                        September 30            September 30
                                    2011        2010        2011        2010
                             Gross   Net Gross   Net Gross   Net Gross   Net
Gas                              -     -     3   2.5     -     -    23  19.0
Oil                             21  18.0    11   8.0    41  34.2    16  11.2
Dry                              -     -     -     -     -     -     4   2.8
                            ------------------------------------------------
Total                           21  18.0    14  10.5    41  34.2    43  33.0
----------------------------------------------------------------------------
Success rate (%)              100%  100%  100%  100%  100%  100%   91%   92%
----------------------------------------------------------------------------

During the third quarter of 2011, the Company drilled 21 gross (18.0 net capital, 16.4 net revenue) Cardium horizontal light oil wells. In addition, the Company brought 17 gross (13.4 net revenue) Cardium horizontal light wells on-stream. Approximately $11.4 million was spent on facilities and well equipment during the third quarter of 2011.

In the third quarter of 2011, the Company sold 83 BOPD (89 BOED) of non-core, heavy oil production and other assets for proceeds of $6.2 million.

RESERVES

GLJ Petroleum Consultants ("GLJ"), an independent reserves evaluator, has completed an interim reserves report of all of the Company's oil & natural gas properties effective October 1, 2011, prepared in accordance with procedures and standards contained in the Canadian Oil and Gas Evaluation ("COGE") Handbook. The reserves definitions used in preparing the interim report are those contained in the COGE Handbook and the Canadian Securities Administrators National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities. This is not a year end reserves report. The October 1, 2011 report is the first step in a process and will be updated by GLJ for year end reserves reporting. At October 1, 2011, the Company's proved developed producing ("PDP"), total proved ("TP") and proved plus probable ("P&P") reserves were 12.4 MMBOE, 19.5 MMBOE and 35.8 MMBOE respectively.

Oil now represents 18% of the Company's PDP, 15% of TP and 18% of the P&P reserves as compared to 11%, 11% and 12% respectively at December 31, 2010. The Company increased PDP, TP and P&P oil reserves by 72%, 28% and 62% in the previous nine months.

SUMMARY OF OIL AND GAS RESERVES


                                         October 1, 2011
                                                                     Before
                                                                        tax
                                                                        NPV
                         Oil(1)        NGL    Gas(1)       Total     10%(2)
                        (Mbbls)    (Mbbls)     (MMcf)     (MBOE)       ($M)
Proved developed
 producing                2,242      1,460     52,069     12,379    207,113
Proved developed
 producing and
 proved developed
 non-producing            2,375      1,512     59,213     13,755    219,933
Total proved              2,840      1,703     89,842     19,517    227,772
Proved plus probable      6,334      3,185    157,525     35,773    349,575
---------------------------------------------------------------------------

                                        December 31, 2010
                                                                     Before
                                                                        tax
                                                                        NPV
                         Oil(1)        NGL     Gas(1)     Total      10%(2)
                        (Mbbls)    (Mbbls)     (MMcf)     (MBOE)       ($M)
Proved developed
 producing                1,303      1,376     52,498     11,428    166,058
Proved developed
 producing and
 proved developed
 non-producing            1,471      1,426     59,955     12,889    175,619
Total proved              2,226      1,673     97,313     20,117    184,248
Proved plus probable      3,908      2,676    150,621     31,687    271,469
---------------------------------------------------------------------------

(1) Coal Bed Methane is not material to report separately and is included in
the Natural Gas category. Heavy Oil is not material to report separately and
is included in the Oil category.

(2) 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.


SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
As at October 1, 2011
GLJ Forecast Prices and Costs
                    Oil         Natural Gas     Edmonton Liquids Prices
                          Light,
                     Sweet Crude   AECO Gas                         Pentanes
          WTI Cushing   Edmonton      Price    Propane     Butane       Plus
Year        ($US/bbl) ($Cdn/bbl) ($Cdn/Mcf) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl)
2011 Q4         85.00      91.84       3.90      55.10      70.71     100.10
2012            90.00      94.39       4.36      59.46      72.68      97.22
2013            95.00      96.94       4.59      61.07      74.64      98.88
2014           100.00     101.02       5.05      63.64      77.79     103.04
2015           100.00     101.02       5.51      63.64      77.79     103.04
2016           100.00     101.02       5.97      63.64      77.79     103.04
2017           101.36     102.41       6.43      64.52      78.85     104.46
2018           103.38     104.47       6.86      65.82      80.44     106.56
2019           105.45     106.58       7.00      67.15      82.07     108.71
2020           107.56     108.73       7.14      68.50      83.73     110.91
Thereafter 2%
----------------------------------------------------------------------------

SUMMARY OF PRICING AND INFLATION
 RATE ASSUMPTIONS
As at October 1, 2011
GLJ Forecast Prices and Costs

                        Exchange
            Inflation       rate
Year           Rate %  (US$/Cdn)
2011 Q4           2.0       0.98
2012              2.0       0.98
2013              2.0       0.98
2014              2.0       0.98
2015              2.0       0.98
2016              2.0       0.98
2017              2.0       0.98
2018              2.0       0.98
2019              2.0       0.98
2020              2.0       0.98
Thereafter
 2%
--------------------------------

SHARE INFORMATION

The Company's shares have been listed on the Toronto Stock Exchange since September 7, 2005 under the symbol "AXL". As of November 14, 2011, there were 172.5 million common shares outstanding, 14.3 million stock options outstanding, $50.0 million principal amount of convertible debentures which are convertible into common shares at a conversion price of $1.55 per common share and $46.0 million principal amount of convertible debentures which are convertible into common shares at a conversion price of $1.70 per common share. There were no common shares issued in the third quarter of 2011 or the third quarter of 2010 under the employee stock option plan.


                              Three months ended           Nine months ended
                                    September 30                September 30
                              2011          2010          2011          2010
High                 $        0.87 $        1.24 $        1.36 $        1.57
Low                  $        0.42 $        0.95 $        0.42 $        0.95
Close                $        0.43 $        1.12 $        0.43 $        1.12
Volume                  23,739,995    18,034,164   108,708,081    88,346,700
Shares outstanding
 at September 30       172,549,701   172,400,401   172,549,701   172,400,401
Market
 capitalization at
 September 30        $  74,196,371 $ 193,088,449 $  74,196,371 $ 193,088,449
----------------------------------------------------------------------------

The statistics above include trading on the Toronto Stock Exchange only. Shares also trade on alternative platforms like Alpha, Chi-X, Pure and Omega. During the three and nine months ended September 30, 2011, approximately 11.6 million and 77.3 million common shares traded on these alternative exchanges respectively.

ELIMINATION OF DEFICIT

On May 16, 2011 the Company's shareholders approved an ordinary resolution to eliminate the Company's accumulated deficit at January 1, 2011 against share capital without reduction to stated capital or paid up capital. The Company's accumulated deficit at January 1, 2011 was largely the result of the implementation of IFRS combined with the significant reduction in natural gas prices in recent years which reduced profitability and resulted in write downs of historical costs. The Company believes that the elimination of the consolidated accounting deficit, in connection with the implementation of IFRS, is beneficial on a go-forward basis. The accounting adjustment should allow shareholders to better evaluate the Company's performance under IFRS reporting as well as measure the success of the Company's response to detrimental changes in the natural gas business by transitioning to a more oil-weighted company.

LIQUIDITY AND CAPITAL RESOURCES

At September 30, 2011, the Company had outstanding long-term bank loans of $51.8 million, convertible debentures of $96.0 million (principal) and a working capital deficiency of $56.7 million, excluding the unrealized gain on derivative contracts. The working capital deficiency is due to accruals associated with the capital program. The following table shows the changes in bank loans plus cash working capital deficiency:


                              Three months ended           Nine months ended
                                    September 30                September 30
                                            2010                        2010
(thousands of dollars)        2011    (restated)          2011    (restated)
Bank loans plus cash
 working capital
 deficiency, beginning
 of period            $    (71,464) $    (70,284) $    (71,507) $   (72,524)
Funds from operations       12,655         7,876        37,467        27,234
Net cash capital
 expenditures              (49,713)      (39,378)     (118,351)     (85,269)
Proceeds from issue of
 convertible
 debentures, net of
 issue costs                     -             -        43,860             -
Proceeds from issue of
 share capital, net of
 issue costs                     -             -             -        29,792
Proceeds from exercise
 of stock options                -             -            51             -
Decommissioning
 expenditures                  (61)        (412)          (103)      (1,431)
                       -------------------------   -------------------------
Bank loans plus cash
 working capital
 deficiency, end of
 period               $   (108,583) $   (102,198) $   (108,583) $  (102,198)
----------------------------------------------------------------------------

The Board of Directors approved an increase to the Company's 2011 capital budget to $145 million, net of dispositions, of which $118.4 million was spent in the first nine months of 2011. The Company was committed to drill 74 Edmonton Sands gas wells under its farm-in agreement by March 31, 2012. In October 2011, the commitment date was extended to March 31, 2013. The Company does not plan to drill any additional Edmonton Sands gas wells until after 2012. The Company now plans to drill 51 gross (44.3 net capital, 39.1 net revenue) Cardium oil wells in 2011, of which 40 gross (34.1 net capital, 30.2 net revenue) have been drilled to date in 2011.

The Company's need for capital will be both short-term and long-term in nature. Short-term capital is required to finance accounts receivable and other similar short-term assets while the acquisition and development of oil and natural gas properties requires larger amounts of long-term capital. At September 30, 2011, the Company had total credit facilities of $135 million and $83.0 million of credit available under these facilities. On June 8, 2011, the Company completed a convertible subordinated debenture financing for proceeds, net of commission and expenses, of $43.9 million. The net proceeds were initially used to pay down bank debt. The availability created in the credit facilities, along with cash flows, will be prudently used to finance the Company's 2011 and 2012 capital programs. The available lending limits under the bank facilities are reviewed twice a year and are based on the bank syndicate's interpretation of the Company's reserves and future commodity prices. The bank syndicate is currently reviewing the Company's credit facilities and is scheduled to be completed by the end of November 2011. While the Company does not anticipate any changes to the total amounts available under the credit facilities, there can be no assurance that the amounts available or the applicable margins will not be adjusted. As the Company plans to fund its 2012 capital program from a combination of cash flow, existing credit facilities and asset dispositions, oil and natural gas prices will impact the level of capital spending in 2012.

CONTRACTUAL OBLIGATIONS

The Company enters into various contractual obligations in the course of conducting its operations. These obligations include:


--  Loan agreements - The reserves-based extendible, revolving term credit
    facility and working capital credit facility have a revolving period
    ending on July 11, 2012, extendible at the option of the lenders. If not
    extended, the facilities cease to revolve and all outstanding advances
    thereunder become repayable one year from the term date of July 11,
    2012. The supplemental facility is available on a revolving basis and
    expires on July 11, 2012 with any amounts outstanding due in full at
    that time. No amounts were drawn under the supplemental facility at
    September 30, 2011.
--  Convertible debentures - The Company has $96.0 million (principal) in
    convertible debentures outstanding at September 30, 2011, of which $50.0
    million bears interest at 7.5% ("Series A Convertible Debentures") and
    $46.0 million bears interest at 7.25% ("Series B Convertible
    Debentures"). The convertible debentures have a face value of $1,000
    with interest payable semi-annually. The Series A Convertible Debentures
    mature on January 31, 2016 with interest payable on the last day of July
    and January, commencing July 31, 2011. These convertible debentures
    are convertible at the holder's option at a conversion price of $1.55
    per common share, subject to adjustment in certain events and are not
    redeemable by the Company before January 31, 2014. The Series B
    Convertible Debentures mature on June 30, 2017 with interest payable on
    the last day of June and December, commencing December 31, 2011. These
    convertible debentures are convertible at the holder's option at a
    conversion price of $1.70 per common share, subject to adjustment in
    certain events and are not redeemable by the Company before June 30,
    2014.
--  Lease for office space - This lease expires on November 30, 2012. Future
    minimum lease payments are expected to be $0.5 million for the remainder
    of 2011, and $1.6 million in 2012.
--  Firm service transportation commitments - The Company has entered into
    firm service transportation agreements for approximately 23 million
    cubic feet per day of gas sales for various terms expiring between 2011
    and 2020. Based on rate schedules announced to date, the payments in
    each of the next five years and thereafter are estimated to be $0.4
    million for the remainder of 2011, $1.3 million in 2012, $0.9 million in
    2013, $0.7 million in 2014, $0.6 million in 2015 and $0.4 million
    thereafter.
--  Oil transportation contract - In 2010, the Company entered into a
    facilities construction and operation agreement pursuant to which it is
    committed to ship a minimum volume of gross crude oil through new
    facilities and pipelines being constructed in Garrington. The total
    financial commitment is $2.6 million to be incurred over a minimum of
    five years. The contract contains a minimum volume requirement per year
    for the first five years following completion of construction which was
    completed in October 2011. In the event that the volume shipped is less
    than the minimum volume, the Company will be subject to a fee per cubic
    metre of oil on the difference between actual volumes shipped and the
    minimum volume required. Conversely, if the Company exceeds the minimum
    volume requirement in a single year, the excess is carried forward as a
    credit to the minimum volume requirement in the subsequent year. If no
    volumes were shipped, the minimum of $0.26 million would be payable each
    year. After the total contracted volumes have been shipped, the contract
    will automatically renew for one year periods unless terminated.
--  Farm-in - On January 30, 2009, the Company announced a farm-in agreement
    with a large international oil and gas company on lands near its
    existing core operations. Under the farm-in agreement, the Company has
    access to 388 gross (205 net) sections of land. During the commitment
    phase of the transaction, the Company is committed to drill, complete
    and equip 200 wells to earn an interest in up to 120 sections. The
    Company has drilled 126 wells under the commitment to September 30,
    2011. The Company is obligated to complete the drilling of the remaining
    wells on or before March 31, 2013. The commitment is subject to certain
    guarantees. The Company estimates that its minimum commitment to drill
    the remaining 74 wells is $10 million. The Company currently plans to
    defer its spending on the farm-in project until after 2012.

These obligations are described further in note 15 to the interim consolidated financial statements for the three and nine months ended September 30, 2011 and 2010.

INTERNATIONAL FINANCIAL REPORTING STANDARDS

The Company adopted IFRS effective January 1, 2011. As a result, the Company's financial results for the nine months ended September 30, 2011 and comparative periods are reported under IFRS while selected historical data before 2010 continues to be reported under previous CGAAP. (Refer to note 17 of the interim consolidated financial statements for the period ended March 31, 2011 note 16 for the period ended September 30, 2011 for the Company's assessment of the impacts of the transition to IFRS).

NEW AND PENDING ACCOUNTING STANDARDS

The Company is currently evaluating the impact of new and pending accounting standards.

IFRS 9 - Financial Instruments. In November 2009, the IASB published IFRS 9 "Financial Instruments" which covers the classification and measurement of financial assets as part of its project to replace IAS 39 "Financial Instruments: Recognition and Measurement." IFRS 9 uses a single approach to determine whether a financial asset is measured at amortized cost or fair value, replacing the multiple rules in IAS 39. The approach in IFRS 9 is based on how an entity managed its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets. The new standard also requires a single impairment method to be used, replacing the multiple impairment methods in IAS 39.

In October 2010, additional requirements for classifying and measuring financial liabilities were added to IFRS 9. Under this guidance, entities have the option to recognize financial liabilities at fair value through profit or loss. If this option is elected, entities would be required to reverse the portion of the fair value change due to own credit risk out of profit or loss and recognize the change in other comprehensive income.

On August 4, 2011, the IASB issued an exposure draft proposing to change the mandatory effective date of IFRS 9 to annual periods beginning on or after January 1, 2015 from the original effective date of January 1, 2013. Early adoption is permitted and the standard is required to be applied retrospectively. The comment period for this exposure draft closed on October 21, 2011. The implementation of the issued standard is not expected to have a significant impact on the Company's financial position or results.

Reporting Entity. In May 2011, the IASB issued IFRS 10 Consolidated Financial Statement, IFRS 11 Joint Arrangements, IFRS 12 Disclosures of Interests in Other Entities, and amendments to IAS 27 Separate Financial Statements and IAS 28 Investments in Associates and Joint Ventures.

IFRS 10 creates a single consolidation model by revising the definition of control in order to apply the same control criteria to all types of entities, including joint arrangements, associates and special purpose vehicles. IFRS 11 establishes a principle-based approach to the accounting for joint arrangements by focusing on the rights and obligations of the arrangement and limits the application of proportionate consolidation accounting to arrangements that meet the definition of a joint operation.

IFRS 12 is a comprehensive disclosure standard for all forms of interests in other entities, including joint arrangements, associates and special purpose vehicles.

Retrospective application of these standards with relief for certain transactions is effective for fiscal years beginning on or after January 1, 2013, with earlier application permitted if all five standards are collectively adopted.

IFRS 13 - Fair Value Measurement. In May 2011, the IASB issued IFRS 13 Fair Value Measurement, which establishes a single source of guidance for all fair value measurements; clarifies the definition of fair value; and enhances the disclosures on fair value measurement. Prospective application of this standard is effective for fiscal years beginning on or after January 1, 2013, with early application permitted.

IAS 12 - Income Taxes. IAS 12 "Income Taxes" was amended on December 20, 2010 to remove subjectivity in determining on which basis an entity measures the deferred tax relating to an asset. The amendment introduces a presumption that an entity will assess whether the carrying value of an asset will be recovered through the sale of the asset. The amendment to IAS 12 is effective for reporting periods beginning on or after January 1, 2012.

CONTROLS AND PROCEDURES

The Chief Executive Officer ("CEO") and the Chief Financial Officer ("CFO") have designed, or caused to be designed under their supervision, disclosure controls and procedures ("DC&P) and internal controls over financial reporting ("ICOFR") as defined in National Instrument 52-109 Certification of Disclosure in Issuer's Annual and Interim Filings in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with IFRS.

The DC&P have been designed to provide reasonable assurance that material information relating to the Company is made known to the CEO and CFO by others and that information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by the Company under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation. The Company's CEO and CFO have concluded, based on their evaluation as of the end of the period covered by the interim filings, that the Company's disclosure controls and procedures are effective to provide reasonable assurance that material information related to the issuer is made known to them by others within the Company.

The CEO and CFO are required to cause the Company to disclose any change in the Company's ICOFR that occurred during the most recent interim period that has materially affected, or is reasonably likely to materially affect, the Company's ICOFR. No changes in ICOFR were identified during such period that have materially affected or are reasonably likely to materially affect the Company's ICOFR. There were no changes to ICOFR as a result of the transition to IFRS.

It should be noted a control system, including the Company's DC&P and ICOFR, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objective of the control system will be met and it should not be expected that DC&P and ICOFR will prevent all errors or fraud.

BUSINESS 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 had increased earlier this year, and continue to remain volatile as they are a geopolitical commodity, affected by concerns about economic markets in the U.S. and Europe and continued instability in oil producing countries. The industry is subject to extensive governmental regulation with respect to the environment. Operational risks include well performance, uncertainties inherent in estimating reserves, timing of/ability to obtain drilling licences and other regulatory approvals, ability to obtain equipment, expiration of licences and leases, competition from other producers, sufficiency of insurance, ability to manage growth, reliance on key personnel, third party credit risk and appropriateness of accounting estimates. These risks are described in more detail in the Company's Annual Information Form for the year ended December 31, 2010 filed with Canadian securities regulatory authorities on SEDAR.

The Company anticipates making substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future. As the Company's revenues may decline as a result of decreased commodity pricing, it may be required to reduce capital expenditures. In addition, uncertain levels of near term industry activity coupled with the present global economic concerns exposes the Company to additional access to capital risk. There can be no assurance that debt or equity financing, or funds generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Company. The inability of the Company to access sufficient capital for its operations could have a material adverse effect on the Company's business, financial condition, results of operations and prospects.

Anderson manages these risks by employing competent professional staff, following sound operating practices and using capital prudently. The Company generates its exploration prospects internally and performs extensive geological, geophysical, engineering, and environmental analysis before committing to the drilling of new prospects. Anderson seeks out and employs new technologies where possible. With the Company's extensive drilling inventory and advance planning, the Company believes it can manage the slower pace of regulatory approvals and the requirements for extensive landowner consultation.

The Company has a formal emergency response plan which details the procedures employees and contractors will follow in the event of an operational emergency. The emergency response plan is designed to respond to emergencies in an organized and timely manner so that the safety of employees, contractors, residents in the vicinity of field operations, the general public and the environment are protected. A corporate safety program covers hazard identification and control on the jobsite, establishes Company policies, rules and work procedures and outlines training requirements for employees and contract personnel.

The Company currently deals with a small number of buyers and sales contracts, and endeavors to ensure that those buyers are an appropriate credit risk. The Company continuously evaluates the merits of entering into fixed price or financial hedge contracts for price management.

The oil and natural gas business is subject to regulation and intervention by governments in such matters as the awarding of exploration and production interests, the imposition of specific drilling obligations, environmental protection controls, control over the development and abandonment of fields (including restrictions on production) and possibly expropriation or cancellation of contract rights. As well, governments may regulate or intervene with respect to prices, taxes, royalties and the exportation of oil and natural gas. Such regulation may be changed from time to time in response to economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for oil and natural gas, increase the Company's costs or affect its future opportunities.

The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation. Such legislation provides for restrictions and prohibitions on the release or emission of various substances produced in association with certain oil and gas industry operations. Such legislation may also impose restrictions and prohibitions on water use or processing in connection with certain oil and gas operations. In addition, such legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with such legislation can require significant expenditures and a breach of such requirements may result, amongst other things in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage, and the imposition of material fines and penalties.

The Government of Alberta implemented a new oil and gas royalty framework effective January 2009. The new framework establishes new royalties for conventional oil, natural gas and bitumen that are linked to price and production levels and apply to both new and existing conventional oil and gas activities and oil sands projects. Under the framework, the formula for conventional oil and natural gas royalties uses a sliding rate formula, dependent on the market price and production volumes. On March 3, 2009, June 11, 2009 and June 25, 2009, the Government of Alberta announced amendments to the framework. This incentive program included a drilling credit for new oil and natural gas wells drilled between April 1, 2009 and March 31, 2011, providing a $200 per metre drilled royalty credit to companies. The credit was used to offset up to 50% of Crown royalties paid after the wells have been drilled up until March 31, 2011. There is also a new well incentive program that provides a maximum 5% royalty rate for the first 12 months of production from new wells that begin producing oil or natural gas between April 1, 2009 and March 31, 2011 to a maximum of 50,000 barrels of oil or 500 million cubic feet of natural gas.

On March 11, 2010, the Alberta government announced its intention to adjust royalty rates effective January 1, 2011. This adjustment included making the incentive program royalty rate of 5% on new natural gas and conventional oil wells a permanent feature of the royalty system with the time and volume limits discussed above. The maximum royalty rate was reduced from 50% to 40% for conventional oil and to 36% for natural gas.

Changes to the royalty regime in the Province of Alberta are subject to certain risks and uncertainties. There may be modifications introduced to the royalty structure and such changes may be adverse to the business of the Company. There can be no assurance that the Government of Alberta or the Government of Canada will not adopt new royalty regimes which may render the Company's projects uneconomic or otherwise adversely affect the business of the Company.

BUSINESS PROSPECTS

The Company believes it has an excellent future drilling inventory in the Cardium light oil horizontal oil play and is focused on growing its production and reserves with Cardium horizontal drilling. The Company has 124.5 gross (74.0 net) sections in the Cardium fairway and has identified an inventory of 204 gross (129.8 net revenue) drill ready Cardium horizontal oil locations, of which 62 gross (45.6 net revenue) have been drilled to September 30, 2011. The Company continues to add to its land position and drilling inventory through a combination of acquisitions, property swaps and farm-ins, and continues to implement new technologies to control and reduce its costs in this project.

The Company's goal is to grow its oil production to achieve 50% of total production from oil and NGL by sometime in 2012. The capital budget for 2011 is $145 million and annual production guidance for 2011 is between 7,500 and 8,000 BOED. The Company could have considered a budget which yielded higher BOED production growth through spending on natural gas prospects, but elected to proceed with a 100% oil capital budget which has not created BOED production growth, but has yielded substantially higher cash flows through stronger netbacks.

Risks associated with the production guidance provided include continued low commodity prices which may restrict capital spending, new well performance, gas plant capacity, gas plant turnaround duration, regulatory issues, weather problems and access to industry services.

QUARTERLY INFORMATION

The following table provides financial and operating results for the last eight quarters. Commodity prices remain volatile, affecting funds from operations and earnings throughout those quarters. In 2010, the Company changed its focus to oil projects in light of the continued depressed natural gas market, and suspended its shallow gas drilling program until natural gas prices improve. Revenues, funds from operations and earnings (loss) over the past three quarters reflect the benefits from increased sales of crude oil volumes. Also, earnings were affected in each of the four quarters in 2010 by impairments in the value of property, plant and equipment related to natural gas and natural gas liquids reserves values. With the volatility in commodity prices, in the third quarter of 2011 a portion of previously recognized impairments were reversed and additional impairments taken. Earnings were also affected in the third quarter of 2011 by hedging gains and gains on the sale of assets.

Note that the quarterly table contains both IFRS and CGAAP numbers. Comparatives before 2010 have not been restated to reflect the changes in accounting policies as a result of adopting IFRS.


SELECTED QUARTERLY INFORMATION
($ amounts in thousands, except per share amounts and prices)
                                                 IFRS
                                                                     Q4 2010
                              Q3 2011      Q2 2011      Q1 2011   (restated)
                        ----------------------------------------------------
Revenue, net of
 royalties               $     24,970 $     27,776 $     23,283 $     21,690
Funds from operations    $     12,655 $     13,944 $     10,868 $      9,282
Funds from operations
 per share, basic and
 diluted                 $       0.07 $       0.08 $       0.06 $       0.05
Earnings (loss) before
 effect of impairments
 or reversals thereof    $      6,667 $      5,932 $    (3,681) $    (4,864)
Earnings (loss) per
 share before effect of
 impairments or
 reversals thereof
  Basic and diluted      $       0.04 $       0.03 $     (0.02) $     (0.03)
Earnings (loss)          $      7,472 $      5,932 $    (3,681) $   (36,545)
  Basic and diluted      $       0.04 $       0.03 $     (0.02) $     (0.21)
Capital expenditures,
 including acquisitions
 net of dispositions     $     49,713 $     26,284 $     42,354 $     26,240
Cash from operating
 activities              $     11,893 $     14,953 $     11,001 $     10,489
Daily sales
  Natural gas (Mcfd)           30,038       31,990       33,931       38,479
  Oil (bpd)                     1,709        1,759        1,372          992
  NGL (bpd)                       636          667          699          823
  BOE (BOED)                    7,351        7,758        7,726        8,228
Average prices
  Natural gas ($/Mcf)    $       3.85 $       3.79 $       3.58 $       3.48
  Oil ($/bbl)            $      89.05 $      99.39 $      84.71 $      77.62
  NGL ($/bbl)            $      66.07 $      74.24 $      65.97 $      58.87
  BOE ($/BOE)(i)         $      42.16 $      44.71 $      36.80 $      31.63
----------------------------------------------------------------------------

                                           IFRS                        CGAAP
----------------------------------------------------------------------------
                              Q3 2010      Q2 2010      Q1 2010
                           (restated)   (restated)   (restated)      Q4 2009
                          -----------  -----------  -----------  -----------
Revenue, net of
 royalties               $     17,263 $     18,622 $     19,871 $     18,708
Funds from operations    $      7,876 $      8,923 $     10,435 $      9,151
Funds from operations
 per share, basic and
 diluted                 $       0.05 $       0.05 $       0.06 $       0.06
Earnings (loss) before
 effect of impairment    $    (3,057) $    (2,450) $        256 $    (6,457)
Earnings (loss) per
 share before effect of
 impairment
  Basic and diluted      $     (0.02) $     (0.01) $          - $     (0.04)
Loss                     $   (39,029) $    (4,769) $   (44,444) $    (6,457)
Loss per share, basic
 and diluted             $     (0.23) $     (0.03) $     (0.27) $     (0.04)
Capital expenditures,
 including acquisitions
 net of dispositions     $     39,378 $     12,664 $     33,227 $     11,312
Cash from operating
 activities              $      8,287 $      8,811 $     12,746 $      5,361
Daily sales
  Natural gas (Mcfd)           35,778       38,998       35,221       34,938
  Oil (bpd)                       568          491          345          351
  NGL (bpd)                       761          741          785          906
  BOE (BOED)                    7,292        7,732        7,000        7,080
Average prices
  Natural gas ($/Mcf)    $       3.43 $       3.78 $       5.22 $       4.28
  Oil ($/bbl)            $      68.24 $      70.45 $      75.47 $      69.60
  NGL ($/bbl)            $      51.41 $      53.55 $      56.68 $      47.67
  BOE ($/BOE)(i)         $      28.21 $      28.88 $      36.93 $      31.38
----------------------------------------------------------------------------

(i) Includes royalty and other income classified with oil and gas sales and
excludes realized and unrealized gains and losses on derivative contracts.

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; impact of changes in the royalty regime applicable to the Company; estimates of future revenues, costs, netbacks, funds from operations and debt levels; commodity price outlook and general economic outlook may constitute "forward-looking information" (within the meaning of applicable Canadian securities legislation) or "forward-looking statements" (within the meaning of the United States Private Securities Litigation Reform Act of 1995, as amended) and necessarily involve risks and assumptions made by management of the Company including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation; loss of markets; volatility of commodity prices; currency fluctuations; imprecision of reserves estimates; environmental risks; competition from other producers; inability to retain drilling rigs and other services; adequate weather to conduct operations; sufficiency of budgeted capital, operating and other costs to carry out planned activities;

wells not performing as expected; incorrect assessment of the value of acquisitions and farm-ins; failure to realize the anticipated benefits of acquisitions and farm-ins; delays resulting from or inability to obtain required regulatory approvals; changes to government regulation; ability to access sufficient capital from internal and external sources; and other factors, many of which are beyond the Company's control. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as the factors are interdependent, and management's future course of action would depend on its assessment of all information at the time. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements and readers should not place undue reliance on the assumptions and forward-looking statements. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect Anderson's operations and financial results are included in reports on file with Canadian and U.S. securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), the EDGAR website (www.sec.gov/edgar) or at Anderson's website (www.andersonenergy.ca).

Estimates of future revenues, costs, netbacks, funds from operations and debt levels may constitute future oriented financial information or a financial outlook under applicable securities laws, and are presented to provide readers with a comparison to levels in 2009 and 2010 based on the various assumptions described or inherent in the estimates. Readers are cautioned that the information may not be appropriate for other purposes.

This news release contains information regarding forecasts that were obtained from reports prepared by third parties. None of the authors of such reports have provided any form of consultation, advice or counsel regarding any aspect of this news release. Actual outcomes may vary materially from the forecast in such reports, and the prospect for material variation can be expected to increase as the length of the forecast period increases.

The forward-looking statements contained in this news release are made as at the date of this news release and the Company does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

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.
Consolidated Statements of Financial Position
(Stated in thousands of dollars)
(Unaudited)
                                               September 30,  December 31,
                                                   2011           2010

ASSETS
Current assets:
  Cash and cash equivalents                  $             -$         4,024
  Accounts receivable and accruals (note 13)          16,135         20,998
  Prepaid expenses and deposits                        2,689          3,052
  Current portion of unrealized gain on
   derivative contracts (note 13)                      7,551              -
                                              -------------- --------------
                                                      26,375         28,074

Deferred taxes                                        24,493         29,657
Unrealized gain on derivative contracts (note
 13)                                                   1,697              -
Property, plant and equipment (notes 4 and 5)        414,498        320,673
                                              -------------- --------------
                                             $       467,063$       378,404
---------------------------------------------------------------------------
---------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
  Current liabilities:
  Accounts payable and accruals              $        75,560$        46,862
  Unrealized loss on derivative contracts
   (note 13)                                               -          1,918
                                              -------------- --------------
                                                      75,560         48,780

Bank loans (note 6)                                   51,847         52,719
Convertible debentures (note 7)                       84,334         43,460
Decommissioning obligations (note 8)                  60,071         51,550
                                              -------------- --------------
                                                     271,812        196,509
Shareholders' equity:
  Share capital (note 9)                             171,460        426,925
  Equity component of convertible debentures
   (note 7)                                            5,019          2,592
  Contributed surplus                                  9,049          7,921
  Retained earnings (deficit) (note 9)                 9,723       (255,543)
                                              -------------- --------------
                                                     195,251        181,895
Commitments (note 15)
Subsequent event (note 15)
                                              -------------- --------------
                                             $       467,063$       378,404
---------------------------------------------------------------------------
---------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


ANDERSON ENERGY LTD.
Consolidated Statements of Operations and Comprehensive Income (Loss)
(Stated in thousands of dollars, except per share amounts)
(Unaudited)
                             Three months ended          Nine months ended
                                  September 30,               September 30,
                                           2010                        2010
                             2011     (note 16)          2011     (note 16)

Oil and gas sales    $     28,513  $     18,928  $     85,665  $     62,511
Royalties                  (3,543)       (1,665)       (9,636)       (6,755)
                      -----------   -----------   -----------   -----------
Revenue, net of
 royalties                 24,970        17,263        76,029        55,756
Realized gain (loss)
 on derivative
 contracts                    871             -          (353)            -
Unrealized gain on
 derivative
 contracts                  6,350             -        11,166             -
Gain (loss) on sale
 of property, plant
 and equipment              3,476          (388)        4,622           320
                      -----------   -----------   -----------   -----------
                           35,667        16,875        91,464        56,076

Operating expenses          7,590         6,343        23,473        19,962
Transportation
 expenses                     602           172         1,304           387
Depletion and
 depreciation              12,280        10,631        37,976        32,443
Impairment loss
 (reversal) on
 property, plant and
 equipment (note 5)        (1,074)       48,317        (1,074)      110,969
General and
 administrative
 expenses                   2,813         2,425         7,963         6,776
                      -----------   -----------   -----------   -----------
Earnings (loss) from
 operating
 activities                13,456       (51,013)       21,822      (114,461)

Finance income (note
 11)                           21             8            54            72
Finance expenses
 (note 11)                 (3,342)       (1,253)       (8,520)       (3,485)
                      -----------   -----------   -----------   -----------
Net finance expenses       (3,321)       (1,245)       (8,466)       (3,413)

Earnings (loss)
 before taxes              10,135       (52,258)       13,356      (117,874)
Deferred income tax
 expense (benefit)          2,663       (13,229)        3,633       (29,632)
                      -----------   -----------   -----------   -----------
Earnings (loss) and
 comprehensive
 income (loss) for
 the period          $      7,472  $    (39,029) $      9,723  $    (88,242)
---------------------------------------------------------------------------

Basic and diluted
 earnings (loss) per
 share
(note 10)            $       0.04  $      (0.23) $       0.06  $      (0.52)
---------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


ANDERSON ENERGY LTD.
Consolidated Statements of Changes in Shareholders' Equity
(Stated in thousands of dollars, except number of common shares)
(Unaudited)
                                                            Equity
                                                      component of
                     Number of                         convertible
                 Common Shares     Share capital        debentures
Balance at
 January 1,
 2010              150,500,401  $        396,524  $              -
Issued
 pursuant to
 prospectus
 (note 9)           21,900,000            31,755                 -
Share issue
 costs, net of
 tax of $0.5
 million                     -           (1,456)                 -
Share-based
 payments                    -                 -                 -
Loss for the
 period                      -                 -                 -
               ----------------  ----------------  ----------------
Balance at
 September 30,
 2010 (note
 16)               172,400,401           426,823                 -
-------------------------------------------------------------------

Balance at
 January 1,
 2011              172,485,301           426,925             2,592
Elimination of
 deficit (note
 9)                          -         (255,543)                 -
Equity
 component of
 convertible
 debentures,
 net of tax of
 $1.5 million
 (note 7)                    -                 -             2,427
Share-based
 payments                    -                 -                 -
Options
 exercised              64,400                78                 -
Earnings for
 the period                  -                 -                 -
               ----------------  ----------------  ----------------
Balance at
 September 30,
 2011              172,549,701  $        171,460  $          5,019
-------------------------------------------------------------------

ANDERSON ENERGY LTD.
Consolidated Statements of Changes in Shareholders' Equity
(Stated in thousands of dollars, except number of common shares)
(Unaudited)

                                     Retained          Total
                   Contributed       earnings   shareholders
                       surplus      (deficit)       ' equity
Balance at
 January 1,
 2010                    6,338  $   (130,756)  $     272,106
Issued
 pursuant to
 prospectus
 (note 9)                    -              -         31,755
Share issue
 costs, net of
 tax of $0.5
 million                     -              -        (1,456)
Share-based
 payments                1,226              -          1,226
Loss for the
 period                      -       (88,242)       (88,242)
               ---------------  -------------  -------------
Balance at
 September 30,
 2010 (note
 16)                     7,564      (218,998)        215,389
-------------------------------------------------------------

Balance at
 January 1,
 2011                    7,921      (255,543)        181,895
Elimination of
 deficit (note
 9)                          -        255,543              -
Equity
 component of
 convertible
 debentures,
 net of tax of
 $1.5 million
 (note 7)                    -             -          2,427
Share-based
 payments                1,155             -          1,155
Options
 exercised                (27)             -             51
Earnings for
 the period                 -          9,723          9,723
               ---------------  -------------  -------------
Balance at
 September 30,
 2011            $       9,049  $      9,723   $     195,251
-------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


ANDERSON ENERGY LTD.
Consolidated Statements of Cash Flows
NINE MONTHS ENDED SEPTEMBER 30, 2011 AND 2010
 (Stated in thousands of dollars)
(Unaudited)                                               2011         2010
                                                                  (note 16)
CASH PROVIDED BY (USED IN)
OPERATIONS
Earnings (loss) for the period                    $      9,723 $    (88,242)
Adjustments for:
  Depletion and depreciation                            37,976       32,443
  Unrealized gain on derivative contracts              (11,166)           -
  Impairment loss (reversal) on property, plant
   and equipment                                        (1,074)     110,969
  Deferred income tax expense (benefit)                  3,633      (29,632)
  Gain on sale of property, plant and equipment         (4,622)        (320)
  Stock-based compensation                                 730          785
  Accretion on decommissioning obligations               1,295        1,231
  Accretion on convertible debentures                      972            -
  Decommissioning expenditures                            (103)      (1,431)
Changes in non-cash working capital (note 12)              483        4,041
                                                   -----------  -----------
                                                        37,847       29,844
FINANCING
Increase (decrease) in bank loans                         (872)       5,358
Proceeds from issue of convertible debentures, net
 of issue costs (note 7)                                43,860            -
Proceeds from issue of share capital, net of issue
 costs                                                       -       29,792
Proceeds from exercise of stock options                     51            -
Changes in non-cash working capital (note 12)             (253)         103
                                                   -----------  -----------
                                                        42,786       35,253
INVESTING
Property, plant and equipment expenditures            (129,921)     (87,668)
Proceeds from sale of property, plant and
 equipment                                              11,570        2,399
Changes in non-cash working capital (note 12)           33,694       20,171
                                                   -----------  -----------
                                                       (84,657)     (65,098)
                                                   -----------  -----------
Decrease in cash and cash equivalents                   (4,024)          (1)
Cash and cash equivalents, beginning of period           4,024            1
                                                   -----------  -----------
Cash, end of period                               $          - $          -
---------------------------------------------------------------------------

Interest received in cash                         $         54 $         67
Interest paid in cash                             $     (3,721)$     (1,549)
---------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.

ANDERSON ENERGY LTD.

Notes to the Interim Consolidated Financial Statements

THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2011 AND 2010

(Tabular amounts in thousands of dollars, unless otherwise stated)

(Unaudited)

1. REPORTING ENTITY

Anderson Energy Ltd. ("Anderson" or the "Company") was incorporated under the laws of the province of Alberta on January 30, 2002. Anderson is engaged in the acquisition, exploration and development of oil and gas properties in western Canada.

2. BASIS OF PREPARATION

(a) Statement of compliance. The interim consolidated financial statements have been prepared using accounting policies consistent with International Financial Reporting Standards ("IFRS") and in accordance with International Accounting Standard 34 Interim Financial Reporting.

The preparation of financial statements requires management to make judgements, estimates and assumptions that affect the application of policies and reported amounts of assets and liabilities, and revenue and expenses. The estimates and associated assumptions are based on historical experience and various other factors that are believed to be reasonable under the circumstances, the results of which form the basis of making the judgements about carrying values of asset and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.

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

Judgements made by management in the application of IFRS that have a significant effect on the financial statements and estimates with a significant risk of material adjustment in the current and following fiscal years are discussed in note 2(d) of the Company's interim consolidated financial statements for the three months ended March 31, 2011.

These interim consolidated financial statements do not include all of the information required for full annual financial statements. These interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the interim consolidated financial statements for the three months ended March 31, 2011. These interim consolidated financial statements should be read in conjunction with the interim consolidated financial statements and notes thereto for the three months ended March 31, 2011.

The interim consolidated financial statements were authorized for issuance by the Board of Directors on November 14, 2011.

3. SIGNIFICANT ACCOUNTING POLICIES

Significant accounting policies are presented in notes 3 and 4 and the impact of the new standards, including reconciliations presenting the change from previous Canadian Generally Accepted Accounting Principles ("GAAP") to IFRS at January 1, 2010 and December 31, 2010 are presented in note 17 of the Company's interim consolidated financial statements for the three months ended March 31, 2011.

The impacts of the new standards, including reconciliations presenting the change from previous GAAP to IFRS as at September 30, 2010 and for the three and nine months ended September 30, 2010, are presented in note 16 herein.

4. PROPERTY, PLANT AND EQUIPMENT

Cost or deemed cost


                     Oil and natural
                          gas assets     Other equipment              Total
Balance at
 January 1, 2010    $        469,762    $          1,713   $        471,475
Additions                    118,140                  66            118,206
Disposals                     (2,407)                  -             (2,407)
                     -------------------------------------------------------
Balance at
 December 31,
 2010                        585,495               1,779            587,274
Additions                    139,489                  71            139,560
Disposals                    (14,802)                  -            (14,802)
                     -------------------------------------------------------
Balance at
 September 30,
 2011               $        710,182    $          1,850   $        712,032
----------------------------------------------------------------------------

Accumulated depletion, depreciation and impairment losses


                     Oil and natural
                          gas assets     Other equipment              Total
Opening balance
 at January 1,
 2010               $              -    $          1,075   $          1,075
Impairment loss
 at January 1,
 2010                         67,193                   -             67,193
                     -------------------------------------------------------
Balance at
 January 1, 2010              67,193               1,075             68,268
Depletion and
 depreciation for
 the year                     45,484                 168             45,652
Impairment loss              153,165                   -            153,165
Disposals                       (484)                  -               (484)
                     -------------------------------------------------------
Balance at
 December 31,
 2010               $        265,358    $          1,243   $        266,601
Depletion and
 depreciation for
 the period                   37,872                 104             37,976
Impairment
 reversal, net of
 impairment loss              (1,074)                  -             (1,074)
Disposals                     (5,969)                  -             (5,969)
                     -------------------------------------------------------
Balance at
 September 30,
 2011               $        296,187    $          1,347   $        297,534
----------------------------------------------------------------------------

Carrying amounts


                       Oil and natural
                            gas assets    Other equipment              Total
At December 31,
 2010                 $        320,137   $            536   $        320,673
At September 30,
 2011                 $        413,995   $            503   $        414,498
----------------------------------------------------------------------------

Depletion, depreciation and impairment charges. Depletion and depreciation, impairment of property, plant and equipment, and any reversal thereof, are recognized as separate line items in the consolidated statements of operations (see note 5).

5. IMPAIRMENT LOSS AND IMPAIRMENT REVERSAL

At September 30, 2011, there were significant changes in the future commodity price forecasts used by the Company's independent qualified reserves evaluators when compared to December 31, 2010. The Company considered the downward price adjustments on natural gas to be an indicator of impairment for the Company's Shallow Gas and Non-Core CGUs. Similarly, the Company considered the upward price adjustments on natural gas liquids to be an indicator of impairment reversal for its Deep Gas CGU as a result of this CGU having a significant amount of natural gas liquids. All of the Company's oil and gas reserves were evaluated and reported on by independent qualified reserves evaluators at October 1, 2011 ("interim reserves report"). Based on this assessment, the Company determined that $9.7 million of previous impairments were reversed from its Deep Gas CGU and its Shallow Gas and Non-Core CGUs were impaired by $3.2 million and $5.4 million respectively.

As a result of declines in natural gas forward pricing at September 30, 2010, the Company tested the Deep Gas, Shallow Gas and Non-core CGUs for impairment. Based on this assessment at September 30, 2010, the carrying amount of these CGUs were determined to be $48.3 million lower than their recoverable amount and impairments were recorded.

The recoverable amount of the CGUs was estimated based on the fair value less costs to sell. The estimate of fair value less costs to sell for each of the Company's CGUs was determined by reference to information provided in the interim reserves report based on proved plus probable reserves using a pre-tax discount rate of 10%.

The impairment losses and reversals since January 1, 2010 recognized in each CGU were as follows:


                 Horizonta        Deep      Shallow    Non-Core
                 l Oil CGU     Gas CGU      Gas CGU         CGU    Total (1)
Impairment
 loss at
 January 1,
 2010           $        -  $        -   $   67,193  $        -  $   67,193
Impairment
 loss for the
 quarter ended
 March 31,
 2010                    -       6,587       52,827         126      59,540
Impairment
 loss for the
 quarter ended
June 30, 2010            -       3,112            -           -       3,112
Impairment
 loss for the
 quarter ended
 September 30,
 2010                    -      15,996       28,286       4,035      48,317
Impairment
 loss for the
 quarter ended
 December 31,
 2010                    -       5,384       35,033       1,779      42,196
                 -----------------------------------------------------------
Cumulative
 impairment
 loss at
 December 31,
 2010           $        -  $   31,079   $  183,339  $    5,940  $  220,358
Impairment
 loss
 (reversal)
 for the
 quarter ended
 September 30,
 2011                    -      (9,725)       3,207       5,444      (1,074)
                 -----------------------------------------------------------
Cumulative
 impairment
 loss at
 September 30,
 2011           $        -  $   21,354   $  186,546  $   11,384  $  219,284

Carrying
 value,
 December 31,
 2010           $   63,687  $   94,091   $  124,836  $   36,764  $  319,378
Carrying
 value,
 September 30,
 2011           $  177,539  $   96,430   $  107,238  $   25,470  $  406,677
----------------------------------------------------------------------------

(1) Carrying values exclude inventory and corporate assets of $1.3 million at December 31, 2010 and $1.4 million at September 30, 2011.

At September 30, 2011, if the discount rate had been two percent higher or two percent lower, the impairment losses and reversal recognized would have been revised as follows:


               Horizonta        Deep      Shallow     Non-Core
               l Oil CGU     Gas CGU      Gas CGU          CGU        Total
Reduction of
 impairment
 or increase
 in
 impairment
 reversal
 using an 8
 percent
 discount
 rate         $        -  $   (8,021)  $   (8,789)  $   (2,183)  $  (18,993)
Additional
 impairment
 or
 reduction
 of
 impairment
 reversal
 using a 12
 percent
 discount
 rate         $        -  $    6,807   $    7,738   $    1,798   $   16,343
----------------------------------------------------------------------------

6. BANK LOANS

At September 30, 2011, total bank facilities were $135 million consisting of a $100 million extendible revolving term credit facility, a $10 million working capital credit facility and a $25 million supplemental credit facility, with a syndicate of Canadian banks. The extendible revolving term credit facility and the working capital credit facility have a revolving period ending on July 11, 2012. If not extended, the extendible revolving term credit facility and working capital credit facility cease to revolve and all outstanding advances thereunder become repayable one year from the term date of July 11, 2012. The supplemental facility expires on July 11, 2012, with any outstanding amounts due in full at that time.

At September 30, 2011, there were no amounts drawn under the supplemental facility. The average effective interest rate on advances under the facilities in 2011 was 5.7% (September 30, 2010 - 4.9%). The Company had $133,500 in letters of credit outstanding at September 30, 2011 that reduce the amount of credit available to the Company.

Advances under the facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank's prime lending rate, bankers' acceptance or LIBOR loan rates plus applicable margins. These margins vary from 1.50% to 6.00% depending on the borrowing option used and the Company's financial ratios.

Loans are secured by a floating charge debenture over all assets and guarantees by material subsidiaries. Draws over $15 million under the supplemental facility are subject to the consent of the bank syndicate at the time of the drawdown.

The available lending limits of the facilities are reviewed semi-annually and are based on the bank syndicate's interpretations of the Company's reserves and future commodity prices. The bank syndicate is currently reviewing the Company's credit facilities and is scheduled to be completed by the end of November 2011. The Company does not anticipate that there will be any changes to the total amounts available under the facilities, however there can be no assurance that the amount of the available facilities or the applicable margins will not be adjusted.

7. CONVERTIBLE DEBENTURES

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 Corporation before June 30, 2014. On and after June 30, 2014 and prior to June 30, 2016, the Series B Debentures are redeemable at the Corporation's option, in whole or in part, at a price equal to their principal amount plus accrued and unpaid interest if the weighted average trading price of the common shares on the Toronto Stock Exchange for the 20 consecutive trading days preceding the date on which the notice of redemption is given is not less than 125% of the Conversion Price. On or after June 30, 2016 and prior to the Maturity Date, the Series B Debentures may be redeemed in whole or in part at the option of the Corporation on not more than 60 days and not less than 30 days prior notice at a price equal to their principal amount plus accrued and unpaid interest. The Series B Debentures are listed and posted for trading on the TSX under the symbol "AXL.DB.B".

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

The following table indicates the convertible debenture activities:



                                                       Debt          Equity
                                   Proceeds       component       component

Balance, January 1, 2010        $         -     $         -     $         -
Series A Debentures issued
 pursuant to prospectus,
 7.5% interest rate, due
 January 31, 2016(1)                 50,000          45,553           4,447
Issue costs                          (2,300)         (2,095)           (205)
Deferred tax                              -               -          (1,650)
Accretion expense                         -               2               -
                                 -------------------------------------------
Balance, December 31, 2010      $    47,700     $    43,460     $     2,592
Series B Debentures issued
 pursuant to prospectus,
 7.25% interest rate, due
 June 30, 2017(2)                    46,000          41,849           4,151
Issue costs                          (2,140)         (1,947)           (193)
Deferred tax                              -               -          (1,531)
Accretion expense                         -             972               -
                                 -------------------------------------------
Balance, September 30, 2011     $    91,560     $    84,334     $     5,019
----------------------------------------------------------------------------

1.  Includes 1,000 Series A Debentures issued to directors for total gross
    proceeds of $1.0 million.
2.  Includes 1,575 Series B Debentures issued to management and directors
    for total gross proceeds of $1.6 million.

8. DECOMMISSIONING OBLIGATIONS


                                          September 30,        December 31,
                                                   2011                2010
Balance at January 1                   $         51,550    $         47,657
Provisions incurred                               2,328               2,945
Provisions settled                                 (103)             (1,549)
Provisions disposed                              (1,247)                (75)
Change in estimates                               6,248                 918
Accretion expense                                 1,295               1,654
                                        -----------------------------------
Ending balance                         $         60,071    $         51,550
---------------------------------------------------------------------------

The Company's decommissioning obligations result from its ownership interest in oil and natural gas assets including well sites and gathering systems. The total decommissioning obligation is estimated based on the Company's net ownership interest in all wells and facilities, estimated costs to reclaim and abandon these wells and facilities and the estimated timing of the costs to be incurred in future years. The Company has estimated the net present value of the decommissioning obligations to be $60.1 million as at September 30, 2011 (December 31, 2010 - $51.6 million) based on an undiscounted inflation-adjusted total future liability of $76.3 million (December 31, 2010 - $72.9 million). These payments are expected to be made over the next 25 years with the majority of costs to be incurred between 2012 and 2030. At September 30, 2011 the liability has been calculated using an inflation rate of 2.0% (December 31, 2010 - 2.0%) and discounted using a risk-free rate of 0.9% to 3.1% (December 31, 2010 - 0.8% to 4.4%) depending on the estimated timing of the future obligation.

9. SHARE 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.


                                               Number of
                                           Common Shares             Amount
Balance at January 1, 2010                   150,500,401   $        396,524
Issued pursuant to prospectus(1)              21,900,000             31,755
Share issue costs                                      -             (1,963)
Tax effect of share issue costs                        -                507
Stock options exercised                           84,900                 67
Transferred from contributed surplus on
 stock option exercise                                 -                 35
                                         ----------------------------------
Balance at December 31, 2010                 172,485,301   $        426,925
Elimination of deficit                                 -           (255,543)
Stock options exercised                           64,400                 51
Transferred from contributed surplus on
 stock option exercise                                 -                 27
                                         ----------------------------------
Balance at September 30, 2011                172,549,701   $        171,460
---------------------------------------------------------------------------

1.  Includes 352,466 common shares issued to directors for total gross
    proceeds of $0.5 million.

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

Stock options. The Company has an employee stock option plan under which employees, directors and consultants are eligible to purchase common shares of the Company. Options are granted using an exercise price of stock options equal to the weighted average trading price of the Company's common shares for the five trading days prior to the date of the grant. Options have terms of either five or ten years and vest equally over a three year period starting on the first anniversary date of the grant. Changes in the number of options outstanding during the nine months ended September 30, 2011 and the year ended December 31, 2010 are as follows:


                             September 30, 2011            December 31, 2010
                                       Weighted                     Weighted
                                        average                      average
                       Number of       exercise     Number of       exercise
                         options          price       options          price
Outstanding at
 January 1            12,006,232    $      2.32    10,258,756    $      3.22
Granted during the
 period                4,312,300           0.75     3,950,250           1.06
Exercised during the
 period                  (64,400)          0.79       (84,900)          0.79
Expirations during
 the period           (1,456,800)          4.41    (1,430,124)          5.78
Forfeitures during
 the period             (508,300)          1.07      (687,750)          1.44
                    --------------------------------------------------------
Ending balance        14,289,032    $      1.69    12,006,232    $      2.32
----------------------------------------------------------------------------

Exercisable, end of
 period                6,851,932    $      2.59     6,111,399    $      3.53
----------------------------------------------------------------------------

The range of exercise prices of the outstanding options is as follows:


                                                                    Weighted
                                                     Weighted        average
                                 Number of            average remaining life
Range of exercise prices           options     exercise price        (years)

$0.67 to $0.99                   6,390,500   $           0.74            4.1
$1.00 to $1.50                   3,875,150               1.08            3.9
$2.26 to $3.35                     643,950               2.68            2.0
$3.36 to $4.90                   3,379,432               4.00            0.8
                           -------------------------------------------------
Total at September 30, 2011     14,289,032   $           1.69            3.2
----------------------------------------------------------------------------

The weighted average common share price at the date of exercise for stock options exercised in 2011 was $1.20 (December 31, 2010 - $1.02).

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


                                          September 30,       September 30,
                                                   2011                2010
Fair value at grant date               $           0.39    $           0.55
Common share price                     $           0.75    $           1.06
Exercise price                         $           0.75    $           1.06
Volatility                                           59%                 58%
Option life                                     5 years             5 years
Dividends                                             0%                  0%
Risk-free interest rate                            1.67%               2.26%
Forfeiture rate                                      15%                 15%
----------------------------------------------------------------------------

This estimated forfeiture rate is adjusted to the actual forfeiture rate when each tranche vests. Stock-based compensation cost of $0.7 million (September 30, 2010 - $0.8 million) was expensed during the nine months ended September 30 2011. Stock-based compensation cost of $0.2 million (September 30, 2010 - $0.4 million) was expensed during the three months ended September 30 2011. In addition, stock-based compensation expense of $0.5 million (September 30, 2010 - $0.4 million) was capitalized during the nine months ended September 30, 2011. For the three months ended September 30, 2011, $0.2 million of stock-based compensation was capitalized (September 30, 2010 - $0.1 million).

10. EARNINGS (LOSS) PER SHARE

Basic and diluted earnings (loss) per share were calculated as follows:


                             Three months ended           Nine months ended
                                    September 30               September 30
                               2011         2010          2011         2010
Earnings (loss) for
 the period             $     7,472  $   (39,029)  $     9,723  $   (88,242)
----------------------------------------------------------------------------
  Weighted average
   number of common
   shares (basic) (in
   thousands of
   shares)
   Common shares
    outstanding at
    beginning of
    period                  172,550      172,400       172,485      150,500
 Effect of stock
  options exercised               -            -            49            -
 Effect of other
  common shares issued            -            -             -       19,069
                         ---------------------------------------------------
  Weighted average
   number of common
   shares (basic)           172,550      172,400       172,534      169,569
 Effect of dilutive
  stock options                   -            -           506            -
                         ---------------------------------------------------
  Weighted average
   number of common
   shares (diluted)     $   172,550  $   172,400   $   173,040  $   169,569
----------------------------------------------------------------------------

  Basic and diluted
   earnings (loss) per
   common share         $      0.04  $     (0.23)  $      0.06  $     (0.52)
----------------------------------------------------------------------------

The average market value of the Company's common shares for purposes of calculating the dilutive effect of stock options was based on quoted market prices for the period that the options were outstanding. For the three months ended September 30, 2011, 14,289,032 options (September 30, 2010 - 13,174,356 options) and 59,316,889 common share reserved for convertible debentures (September 30, 2010 - Nil) were excluded from calculating dilutive earnings as they were anti-dilutive. For the nine months ended September 30, 2011, 11,702,932 options (September 30, 2010 - 13,174,356 options) and 59,316,889 common share reserved for convertible debentures (September 30, 2010 - Nil) were excluded from calculating dilutive earnings as they were anti-dilutive.

11. FINANCE INCOME AND EXPENSES


                           Three months ended             Nine months ended
                                 September 30                  September 30
                          2011           2010           2011           2010
Income:
 Interest income
  on cash
  equivalents      $         -    $         -    $         5    $         -
 Other                      21              8             49             72
Expenses:
  Interest and
   financing
   costs on bank
   loans                  (667)          (829)        (2,376)        (2,223)
 Interest on
  convertible
  debentures            (1,771)             -         (3,859)             -
 Accretion on
  convertible
  debentures              (462)             -           (972)             -
  Accretion on
   decommissioni
   ng
   obligations            (439)          (417)        (1,295)        (1,231)
 Other                      (3)            (7)           (18)           (31)
                    --------------------------------------------------------
Net finance
 expenses          $    (3,321)   $    (1,245)   $    (8,466)   $    (3,413)
----------------------------------------------------------------------------

12. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in non-cash working capital is comprised of:


                                          September 30,        September 30,
                                                   2011                 2010
Source (use) of cash
 Accounts receivable and accruals      $          4,863     $          2,861
 Prepaid expenses and deposits                      363                  263
 Accounts payable and accruals                   28,698               21,191
                                        ------------------------------------
                                       $         33,924     $         24,315
----------------------------------------------------------------------------
Related to operating activities        $            483     $          4,041
Related to financing activities        $           (253)    $            103
Related to investing activities        $         33,694     $         20,171
----------------------------------------------------------------------------

13. FINANCIAL RISK MANAGEMENT

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


--  credit risk;
--  liquidity risk; and
--  market risk.

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

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

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


                                           September 30,        December 31,
                                                    2011                2010
Cash and cash equivalents               $              -    $          4,024
Accounts receivable and accruals                  16,135              20,998
                                         -----------------------------------
                                        $         16,135    $         25,022
----------------------------------------------------------------------------

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

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

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

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

The Company's allowance for doubtful accounts as at September 30, 2011 was $0.9 million (December 31, 2010 - $1.0 million). This allowance was mostly created in prior years and is associated with prior corporate acquisitions and potential joint venture billing disputes. The Company wrote-off $0.1 million in receivables during the nine months ended September 30, 2011 (September 30, 2010 - $Nil). The Company would only choose to write-off a receivable balance (as opposed to providing an allowance) after all reasonable avenues of collection had been exhausted.

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


                                                             Carrying amount
                                           September 30,        December 31,
                                                    2011                2010
Oil and natural gas marketing
 companies                              $          9,941    $          9,286
Joint venture partners                             4,654               7,989
Other                                              1,540               3,723
                                         -----------------------------------
                                        $         16,135    $         20,998
----------------------------------------------------------------------------

As at September 30, 2011 and December 31, 2010, the Company's accounts receivable and accruals was aged as follows:


                                     September 30,        December 31,
Aging                                         2011                2010
Not past due                      $         14,896    $         18,960
Past due by less than 120 days               1,083               1,706
Past due by more than 120 days                 156                 332
                                   -----------------------------------
Total                             $         16,135    $         20,998
----------------------------------------------------------------------

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

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

To achieve this objective, the Company prepares annual capital expenditure budgets, which are regularly monitored and updated as considered necessary. The Company uses authorizations for expenditures on both operated and non operated projects to further manage capital expenditures. To provide capital when needed, the Company has revolving reserves-based credit facilities which are reviewed semi-annually by its lenders. These facilities are described in note 6. The Company also attempts to match its payment cycle with collection of oil and natural gas revenue on the 25th of each month.

The following are the contractual maturities of financial liabilities, including associated interest payments on convertible debentures and excluding the impact of netting agreements at September 30, 2011:


                      Less                         Three
                      than    One to    Two to        to   Four to   Five to
Financial              one       two    three       four      five       six
 Liabilities          year     years     years     years     years     years
Non-derivative
 financial
 liabilities
 Accounts
  payable and
  accruals (1)    $ 75,560  $      -  $      -  $      -  $      -  $      -
 Bank loans -
  principal (2)          -    51,847         -         -         -         -
 Convertible
  debentures
  - Interest (1)     5,626     7,085     7,085     7,085     5,210     3,335
  - Principal            -         -         -         -    50,000    46,000
                   ---------------------------------------------------------
Total             $ 81,186  $ 58,932  $  7,085  $  7,085  $ 55,210  $ 49,335
----------------------------------------------------------------------------

1.  Accounts payable and accruals includes $1.7 million of interest relating
    to convertible debentures. The total cash interest payable in less than
    one year on the convertible debentures is $7.3 million.
2.  Assumes the credit facilities are not renewed on July 11, 2012.

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

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

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

There were no financial instruments denominated in U.S. dollars at September 30, 2011 or December 31, 2010.

Interest rate risk. Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The interest charged on the outstanding bank loans fluctuates with the interest rates posted by the lenders. The Company has not entered into any mitigating interest rate hedges or swaps, however the Company has $50 million and $46 million of convertible debentures with fixed interest rates of 7.5% and 7.25% respectively, maturing January 31, 2016 and June 30, 2017 (see note 7). Had the borrowing rate on bank loans been 100 basis points higher (or lower) throughout the nine months ended September 30, 2011, earnings would have been affected by $0.3 million (September 30, 2010 - $0.2 million) based on the average bank debt balance outstanding during the period.

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

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

At September 30, 2011 the following derivative contracts were outstanding and recorded at estimated fair value:



                                           Weighted Average
                                                Fixed Price
                                                     (NYMEX
Type of Contract(1) Commodity  Volume           Canadian $) Remaining Period
                                 1,250                        Oct 1, 2011 to
Financial swap      Crude oil bbls/day   $        91.96/bbl     Dec 31, 2011
                                   250                        Oct 1, 2011 to
Financial swap      Crude oil bbls/day   $       105.30/bbl     Dec 31, 2011
                                   500                        Jan 1, 2012 to
Financial swap      Crude oil bbls/day   $       106.04/bbl     Mar 31, 2012
                                 1,000                        Jan 1, 2012 to
Financial swap      Crude oil bbls/day   $       103.93/bbl     Dec 31, 2012
----------------------------------------------------------------------------

1.  Swap indicates fixed price payable to Anderson in exchange for floating
    price payable to counterparty.

The estimated fair value of the financial oil contracts has been determined on the amounts the Company would receive or pay to terminate the oil contracts. At September 30, 2011, the Company estimates that it would have received $9.2 million to terminate these contracts.

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


                                           September 30,       December 31,
                                                    2011               2010
Assets:
 Current                                $          7,551   $              -
 Long-term                                         1,697                  -
Current liability                                      -             (1,918)
                                         -----------------------------------
Net asset (liability) position          $          9,248   $         (1,918)
----------------------------------------------------------------------------

The fair value of derivative contracts at September 30, 2011 would have been impacted as follows had the oil prices used to estimate the fair value changed by:


                                            Effect of an         Effect of a
                                             increase in         decrease in
                                         price on after-     price on after-
                                            tax earnings        tax earnings
Canadian $1.00 per barrel change in
 the oil prices                         $           (410)   $            410
----------------------------------------------------------------------------

In June 2011, the Company entered into physical sales contracts to sell 15,000 GJ per day of natural gas between July 1, 2011 and October 31, 2011 at a weighted average AECO price of $4.06 per GJ. The gains realized to September 30, 2011 were $0.8 million and have been included in oil and gas sales.

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

The Company manages its capital structure and makes adjustments to it in the light of changes in economic conditions and the risk characteristics of the underlying petroleum and natural gas assets. The Company's capital structure includes shareholders' equity of $195.3 million, bank loans of $51.8 million, convertible debentures with a face value of $96.0 million and the working capital deficiency of $56.7 million, excluding the current portion of unrealized gain on derivative contracts. In order to maintain or adjust the capital structure, the Company may from time to time issue shares, seek additional debt financing and adjust its capital spending to manage current and projected debt levels.

Consistent with other companies in the oil and gas sector, Anderson monitors capital based on the ratio of total debt to funds from operations. This ratio is calculated by dividing total debt at the end of the period (comprised of the cash working capital deficiency, the liability component of convertible debentures and outstanding bank loans) by the annualized current quarter funds from operations (cash flow from operating activities before changes in non-cash working capital including decommissioning expenditures). This ratio may increase at certain times as a result of acquisitions, the timing of capital expenditures and market conditions. In order to facilitate the management of this ratio, the Company prepares annual capital expenditure budgets, which are updated as necessary depending on varying factors including current and forecast crude oil and natural gas prices, capital deployment and general industry conditions. The annual and updated budgets are approved by the Board of Directors.


                                         September 30,         December 31,
                                                  2011                 2010
Bank loans                            $         51,847     $         52,719
Current liabilities(1)                          75,560               46,862
Current assets(1)                              (18,824)             (28,074)
---------------------------------------------------------------------------
Net debt before convertible
 debentures                           $        108,583     $         71,507
Convertible debentures (liability
 component)                                     84,334               43,460
---------------------------------------------------------------------------
Total net debt                        $        192,917     $        114,967

Cash from operating activities in
 quarter                              $         11,893     $         10,489
Decommissioning expenditures                        61                  118
Changes in non-cash working
 capital                                           701               (1,324)
---------------------------------------------------------------------------
Funds from operations in quarter      $         12,655     $          9,283
Annualized current quarter funds
 from operations                      $         50,620     $         37,132

Net debt before convertible
 debentures to funds from
 operations                                        2.1                  1.9
Total net debt to funds from
 operations                                        3.8                  3.1
---------------------------------------------------------------------------

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

There were no changes in the Company's approach to capital management during the period.

As at September 30, 2011, the Company's ratio of net debt before convertible debentures to annualized funds from operations was 2.1 to 1 (December 31, 2010 - 1.9 to 1). As at September 30, 2011, the Company's ratio of total net debt to annualized funds from operations was 3.8 to 1 (December 31, 2010 - 3.1 to 1). The high ratios reflect the capital expenditures required to make the transition from a gas weighted company to an oil weighted company. The increase in the ratio from December 31, 2010 is the result higher capital spending in the nine months ended September 30, 2011, partially offset by higher funds from operations as a result of the transition to an oil weighted Company. As new crude oil production is brought on-stream at higher expected operating margins, the debt to funds from operations ratio is expected to decrease.

Neither the Company nor any of its subsidiaries are subject to externally imposed capital requirements. The credit facilities are subject to a semi-annual review of the borrowing base which is directly impacted by the value of the oil and natural gas reserves.

14. RELATED PARTY 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.

On December 31, 2010, the Company issued 1,000 Series A Convertible Debentures to directors at a price of $1,000 per convertible debenture for total gross proceeds of $1.0 million as part of a $50.0 million bought deal offering of convertible debentures.

In February 2010, the Company issued 352,466 common shares to directors at a price of $1.45 per share for total gross proceeds of $0.5 million as part of a $27.9 million bought deal offering of common shares.

15. COMMITMENTS

The Company has entered into an agreement to lease office space until November 30, 2012. Future minimum lease payments are expected to be $0.5 million in the remainder of 2011 and $1.6 million in 2012.

On December 2, 2010, the Company entered into a facilities construction and operation agreement pursuant to which it is committed to ship a minimum volume of gross crude oil through new facilities and pipelines being constructed in one of its core areas. The total financial commitment is $2.6 million to be incurred over a minimum of five years. The contract contains a minimum volume requirement per year for the first five years following completion of construction which is expected to be in the third quarter of 2011. In the event that the volume shipped is less than the minimum volume, the Company will be subject to a fee per cubic metre of oil on the difference between actual volumes shipped and the minimum volume required. Conversely, if the Company exceeds the minimum volume requirement in a single year, the excess is carried forward as a credit to the minimum volume requirement in the subsequent year. If no volumes were shipped, the minimum of $0.26 million would be payable each year. After the total contracted volumes have been shipped, the contract will automatically renew for one year periods unless terminated.

The Company entered into firm service transportation agreements for approximately 23 million cubic feet per day of gas sales in central Alberta for various terms expiring in one to nine years. Based on rate schedules announced to date, the payments in each of the next five years and thereafter are estimated as follows:


                                                Committed          Committed
                                           volume (MMcfd)             amount
Remainder of 2011                                      23   $            416
2012                                                   19   $          1,332
2013                                                    8   $            859
2014                                                    4   $            679
2015                                                    4   $            604
Thereafter                                             12   $            433
----------------------------------------------------------------------------

On January 29, 2009, the Company executed a farm-in agreement with a large international oil and gas company (the "Farmor") on lands near its existing core operations. Under the farm-in agreement, the Company has access to 388 gross (205 net) sections of land. During the commitment phase of the transaction, the Company is committed to drill, complete and equip 200 wells to earn an interest in up to 120 sections. The Company was originally obligated to complete the drilling of the wells on or before March 31, 2012. Subsequent to September 30, 2011, the terms of the farm-in agreement were modified to extend the commitment date to March 31, 2013. The Company's equipping obligation is up to, but does not include, multi-well gathering systems downstream of field compression and/or gas plants. The Company has an option to continue the farm-in transaction until March 1, 2014 by committing to drill a minimum of 100 additional wells under similar terms as in the commitment phase to earn a minimum of 50 sections of land. Following the commitment and/or option phases, the parties to the agreement can then jointly develop the lands on denser drilling spacing under terms of an operating agreement.

The Company commenced drilling in the fourth quarter of 2009 and currently estimates that the average working interest of the 200 well capital commitment will be approximately 80% to 85%, based on partner participation identified to date. As of December 31, 2010, the Company has drilled 126 wells under the farm-in agreement and plans to defer the drilling of the remaining 74 wells until 2012. The Company earns its interest in each well as the well is put on production. A $550,000 penalty is payable for each well not drilled under the commitment as of March 31, 2013, subject to certain reductions due to unavoidable events beyond the Company's control and rights of first refusal. The Company estimates that its minimum commitment to drill the remaining 74 wells is $10 million.

16. RECONCILIATION FROM CANADIAN GAAP TO IFRS

This note sets out how the transition from CGAAP to IFRS has affected the Company's statement of financial position, comprehensive loss and shareholders' equity.

Statement of financial position at September 30, 2010:


                                                Effect of transition to IFRS
                                 Canadian     Impairment    Decommissioning
(in thousands of dollars)            GAAP      (note 16b)         (note 16d)
ASSETS
 Current assets:
  Cash and cash equivalents    $        -   $          -   $              -
  Accounts receivable and
   accruals                        20,129
  Prepaid expenses and
   deposits                         3,515
                                --------------------------------------------
                                   23,644              -                  -

 Property, plant and
  equipment (note 16a)            501,732       (178,162)             1,637
                                --------------------------------------------
                               $  525,376   $   (178,162)  $          1,637
----------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS'
 EQUITY
 Current liabilities:
  Accounts payable and
   accruals                    $   58,080   $          -   $              -

Bank loans                         67,762
 Decommissioning obligations       35,469                            14,757
 Deferred tax liability
  (asset)                          23,263        (44,892)            (3,279)
                                --------------------------------------------
                                  184,574        (44,892)            11,478
 Shareholders' Equity:
Share capital                  $  421,936   $          -   $              -
Contributed surplus                 7,778
Deficit (note 16i)                (88,912)      (133,270)            (9,841)
                                --------------------------------------------
                                  340,802       (133,270)            (9,841)
                               $  525,376   $   (178,162)  $          1,637
----------------------------------------------------------------------------


----------------------------------------------------------------------------

                                                Effect of transition to IFRS
                                    Share-
                                     based     Depletion and     Other PP&E
                                  payments      depreciation          adjs
(in thousands of dollars)        note (16e)        (note 16c)     (note 16c)
ASSETS
 Current assets:
  Cash and cash equivalents    $         -   $             -   $          -
  Accounts receivable and
   accruals
  Prepaid expenses and
   deposits
                             -----------------------------------------------
                                         -                 -              -

 Property, plant and
  equipment (note 16a)                (292)           24,043           (208)
                             -----------------------------------------------
                               $      (292)  $        24,043   $       (208)
----------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS'
 EQUITY
 Current liabilities:
  Accounts payable and
   accruals                    $         -   $             -   $          -

Bank loans
 Decommissioning obligations                                            156
 Deferred tax liability
  (asset)                                              6,050           (361)
                             -----------------------------------------------
                                         -             6,050           (205)
 Shareholders' Equity:
Share capital                  $         -   $             -   $          -
Contributed surplus                   (214)
Deficit (note 16i)                     (78)           17,993             (3)
                             -----------------------------------------------
                                      (292)           17,993             (3)
                               $      (292)  $        24,043   $       (208)
----------------------------------------------------------------------------


----------------------------------------------------------------------------

                                Effect of transition to IFRS
                                Flow through        Deferred
                                shares (note     Taxes (note
(in thousands of dollars)                16f)            16h)          IFRS
ASSETS
 Current assets:
  Cash and cash equivalents    $           -   $           -   $          -
  Accounts receivable and
   accruals                                                          20,129
  Prepaid expenses and
   deposits                                                           3,515
                             -----------------------------------------------
                                           -               -         23,644

 Property, plant and
  equipment (note 16a)                                              348,750
                             -----------------------------------------------
                               $           -   $           -   $    372,394
----------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS'
 EQUITY
 Current liabilities:
  Accounts payable and
   accruals                    $           -   $           -   $     58,080

Bank loans                                                           67,762
 Decommissioning obligations                                         50,382
 Deferred tax liability
  (asset)                                                           (19,219)
                             -----------------------------------------------
                                           -               -        157,005
 Shareholders' Equity:
Share capital                  $       5,336   $        (449)  $    426,823
Contributed surplus                                                   7,564
Deficit (note 16i)                    (5,336)            449       (218,998)
                             -----------------------------------------------
                                           -               -        215,389
                               $           -   $           -   $    372,394
----------------------------------------------------------------------------


----------------------------------------------------------------------------

16. RECONCILIATION FROM CANADIAN GAAP TO IFRS (Continued)

Reconciliation of consolidated statement of operations and comprehensive loss for the three months ended September 30, 2010:


                                                Effect of transition to IFRS
                                             Impairment     Decommissioning
(in thousands of dollars) Canadian GAAP       (note 16b)          (note 16d)

Oil and gas sales        $       18,928  $            -  $                -
Royalties                        (1,665)
                          --------------------------------------------------
Revenue, net of royalties        17,263               -                   -
Loss on sale of property,
 plant and equipment                  -
                          --------------------------------------------------
                                 17,263               -                   -

Operating expenses                6,343
Transportation expenses             172
Depletion and
 depreciation                    18,937
Impairment of property,
 plant and equipment                  -          48,317
General and
 administrative expenses,
 including stock-based
 compensation                     2,377
                          --------------------------------------------------
Loss from operating
 activiites                     (10,566)        (48,317)                  -

Finance income                        8
Finance expenses,
 including accretion             (1,481)                                228
                          --------------------------------------------------
Net finance expenses             (1,473)              -                 228

Loss before taxes               (12,039)        (48,317)                228
Deferred income tax
 benefit                         (2,993)        (12,345)                 57
                          --------------------------------------------------
Loss and comprehensive
 loss for the period     $       (9,046) $      (35,972) $              171
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                                    Effect of transition to IFRS
                              Share-      Depletion
                               based            and   Other PP&E
                            payments   depreciation        adjs
(in thousands of dollars)  (note 16e)     (note 16c)   (note 16c)      IFRS

Oil and gas sales        $         -  $           -  $         -  $  18,928
Royalties                                                            (1,665)
                         ---------------------------------------------------
Revenue, net of royalties          -              -            -     17,263
Loss on sale of property,
 plant and equipment                                        (388)      (388)
                         ---------------------------------------------------
                                   -              -         (388)    16,875

Operating expenses                                                    6,343
Transportation expenses                                                 172
Depletion and
 depreciation                                (8,306)                 10,631
Impairment of property,
 plant and equipment                                                 48,317
General and
 administrative expenses,
 including stock-based
 compensation                   (102)                        150      2,425
                         ---------------------------------------------------
Loss from operating
 activiites                      102          8,306         (538)   (51,013)

Finance income                                                            8
Finance expenses,
 including accretion                                                 (1,253)
                         ---------------------------------------------------
Net finance expenses               -              -            -     (1,245)

Loss before taxes                102          8,306         (538)   (52,258)
Deferred income tax
 benefit                           -          2,090          (38)   (13,229)
                         ---------------------------------------------------
Loss and comprehensive
 loss for the period     $       102  $       6,216  $      (500) $ (39,029)
----------------------------------------------------------------------------

Reconciliation of consolidated statement of operations and comprehensive loss for the nine months ended September 30, 2010:


                                                Effect of transition to IFRS
                                             Impairment     Decommissioning
(in thousands of dollars) Canadian GAAP       (note 16b)          (note 16d)

Oil and gas sales        $       62,511  $            -  $                -
Royalties                        (6,755)
                          --------------------------------------------------
Revenue, net of royalties        55,756               -                   -
Gain on sale of property,
 plant and equipment                  -
                          --------------------------------------------------
                                 55,756               -                   -

Operating expenses               19,962
Transportation expenses             387
Depletion and
 depreciation                    56,486
Impairment of property,
 plant and equipment                  -         110,969
General and
 administrative expenses,
 including stock-based
 compensation                     6,501
                          --------------------------------------------------
Loss from operating
 activiites                     (27,580)       (110,969)                  -

Finance income                       72
Finance expenses,
 including accretion             (4,143)                                658
                          --------------------------------------------------
Net finance expenses             (4,071)              -                 658

Loss before taxes               (31,651)       (110,969)                658
Deferred income tax
 benefit                         (7,761)        (27,978)                165
                          --------------------------------------------------
Loss and comprehensive
 loss for the period     $      (23,890) $      (82,991) $              493
----------------------------------------------------------------------------

                                    Effect of transition to IFRS
                              Share-      Depletion
                               based            and   Other PP&E
                            payments   depreciation        adjs
(in thousands of dollars)  (note 16e)     (note 16c)   (note 16c)      IFRS

Oil and gas sales        $         -  $           -  $         -  $  62,511
Royalties                                                            (6,755)
                         ---------------------------------------------------
Revenue, net of royalties          -              -            -     55,756
Gain on sale of property,
 plant and equipment                                         320        320
                         ---------------------------------------------------
                                   -              -          320     56,076

Operating expenses                                                   19,962
Transportation expenses                                                 387
Depletion and
 depreciation                               (24,043)                 32,443
Impairment of property,
 plant and equipment                                                110,969
General and
 administrative expenses,
 including stock-based
 compensation                   (156)                        431      6,776
                         ---------------------------------------------------
Loss from operating
 activiites                      156         24,043         (111)  (114,461)

Finance income                                                           72
Finance expenses,
 including accretion                                                 (3,485)
                         ---------------------------------------------------
Net finance expenses               -              -            -     (3,413)

Loss before taxes                156         24,043         (111)  (117,874)
Deferred income tax
 benefit                           -          6,050         (108)   (29,632)
                         ---------------------------------------------------
Loss and comprehensive
 loss for the period     $       156  $      17,993  $        (3) $ (88,242)
----------------------------------------------------------------------------

Notes to reconciliations


a.  IFRS 1 - Deemed Cost. The Company applied the IFRS 1 exemption whereby
    the value of its opening plant, property and equipment at January 1,
    2010 was deemed to be equal to the net book value as determined under
    Canadian GAAP and the corresponding CGUs were tested for impairment. The
    Company chose to allocate its costs to its CGUs based on proved plus
    probable reserves volumes.
b.  IAS 36 Adjustments - Impairment of Assets. Under Canadian GAAP,
    impairment of non-financial assets is assessed on the basis of an
    asset's estimated undiscounted future cash flows compared with the
    asset's carrying amount and if impairment is indicated, discounted cash
    flows are prepared to quantify the amount of the impairment. Under IFRS,
    impairment is assessed based on recoverable amount (greater of value in
    use or fair value less costs to sell) compared with the asset's carrying
    amount to determine the recoverable amount and measure the amount of the
    impairment. In addition, under IFRS, where a non-financial asset does
    not generate largely independent cash inflows, the Company is required
    to perform its test at a cash generating unit level, which is the
    smallest identifiable grouping of assets that generates largely
    independent cash inflows. Canadian GAAP impairment is based on
    undiscounted cash flows using asset groupings with both independent cash
    inflows and cash outflows.

Upon transition to IFRS, this resulted in a $67.2 million reduction in property, plant and equipment. For the three months and nine months ended September 30, 2010 as well as the year ended December 31, 2010 the Company recognized impairments of $48.3 million, $111.0 million and $153.2 million respectively with a corresponding reduction in property, plant and equipment as a result of declines in the forward natural gas price curves.


c.  IAS 16 Adjustments - Property, Plant and Equipment.

Depletion and depreciation. Upon transition to IFRS, the Company adopted a policy of depleting and depreciating oil and natural gas interests on a unit of production basis over proved plus probable reserves. The depletion and depreciation policy under Canadian GAAP was based on units of production over proved reserves. In addition, depletion and depreciation was calculated on the Canadian full cost pool under Canadian GAAP. IFRS requires depletion and depreciation to be calculated based on individual components.

For the three months ended September 30, 2010, the use of proved plus probable reserves as well as the lower net book value due to the impairments of the Company's Shallow Gas, Deep Gas and Non-core CGUs resulted in a decrease to depletion and depreciation of $8.3 million with a corresponding increase to property, plant and equipment. For the nine months ended September 30, 2010, depletion and depreciation decreased by $24.0 million for the same reasons.

Other adjustments. IFRS requires that gains or losses be reported on the disposition of property, plant and equipment. Under Canadian GAAP, gains or losses on disposition of property, plant and equipment were only reported when the disposition resulted in more than a 20 percent change in the depletion rate. As a result of this requirement, the Company reported a loss of $0.4 million and gain of $0.3 million during the three and nine months ended September 30, 2010 respectively with an increase in property, plant and equipment where the proceeds were originally recorded under Canadian GAAP and a net increase to decommissioning obligations that were assumed as part of an asset exchange of $0.2 million.

IFRS also requires that the capitalization of general and administrative costs be limited to directly attributable costs. Under Canadian GAAP, a reasonable allocation of general and administrative costs to property, plant and equipment was acceptable. As a result of the change in the capitalization criteria, the Company increased its general and administrative expense by $0.2 million during the three months ended September 30, 2010 and $0.4 million during the nine months ended September 30, 2010 with a corresponding decrease in property, plant and equipment.

Under Canadian GAAP, a deferred tax adjustment was recorded related to stock-based compensation costs capitalized. No such adjustment is made under IFRS. As a result of this change, property, plant and equipment was reduced by $0.3 million at September 30, 2010 with a corresponding decrease to the deferred tax liability.


d.  IAS 37 Adjustments - Provisions, Contingent Liabilities and Contingent
    Assets. Consistent with IFRS, decommissioning obligations (asset
    retirement obligations under Canadian GAAP) were measured under Canadian
    GAAP based on the estimated cost of decommissioning, discounted to their
    net present value upon initial recognition. Under Canadian GAAP, asset
    retirement obligations were discounted at a credit adjusted risk fee
    rate of eight to 10 percent. Under IFRS, the estimated cash flow to
    abandon and remediate the wells and facilities has been risk adjusted,
    therefore the provision is discounted at a risk free rate of one to four
    percent. Decommissioning obligations are also required to be re-measured
    based on changes in estimates including discount rates.

The IFRS 1 exemption was utilized for asset retirement obligations associated with oil and gas properties and the Company re-measured asset retirement obligations as at January 1, 2010 under IAS 37 with a corresponding adjustment to opening retained earnings. Upon transition to IFRS this resulted in a $13.8 million increase in the decommissioning obligations with a corresponding decrease in retained earnings.

At September 30, 2010, using risk-free rates of one to four percent, depending on the estimated timing of the future obligation, the Company increased its decommissioning obligations by $14.8 million from Canadian GAAP. The Company also increased the value of its plant, property and equipment for September 30, 2010 by $1.6 million.

As a result of the change in the decommissioning obligation, accretion expense decreased by $0.2 million during the three months ended September 30, 2010 under IFRS compared to Canadian GAAP. For the nine months ended September 30, 2010, accretion expense decreased by $0.7 million. In addition, under Canadian GAAP accretion of the discount was included in depletion and depreciation. Under IFRS, it is included in finance expenses.


e.  IFRS 2 Adjustments - Share-based Payments. Under Canadian GAAP, the
    Company recognized an expense related to stock-based compensation on a
    straight-line basis through the date of full vesting and incorporated a
    forfeiture multiple, which was optional under Canadian GAAP. Under IFRS,
    the Company is required to recognize the expense over the individual
    vesting periods for the graded vesting awards and estimate a forfeiture
    rate. For the three months ended September 30, 2010, the Company reduced
    the amount of stock-based compensation expense by $0.1 million and
    reduced the amount capitalized by $0.2 million. For the nine months
    ended September 30, 2010, the Company reduced the amount of stock-based
    compensation expense by $0.2 million and reduced the amount capitalized
    by $0.4 million. In addition, under Canadian GAAP, stock-based
    compensation was disclosed separately on the consolidated statement of
    operations and comprehensive loss. Under IFRS, stock-based compensation
    is included in general and administrative expenses.
f.  Flow Through Shares. Under Canadian GAAP, the Company recorded the
    deferred tax impact on renouncement of flow through shares against share
    capital. Under IFRS, the Company is required to record a premium
    liability when the flow through shares are issued, which is relieved
    upon renouncement, with the difference going to deferred tax expense. As
    a result of this change in the treatment of deferred taxes, at
    transition, the Company recorded an additional $5.3 million to share
    capital with a corresponding reduction in retained earnings for flow
    through shares that had been previously issued and fully renounced at
    transition.
g.  Convertible Debentures. Under Canadian GAAP, the Company did not record
    a deferred tax difference on its convertible debentures. Under IFRS, the
    Company is required to record the deferred tax difference between the
    fair value of the liability component of the convertible debentures and
    the tax value of the convertible debentures with the difference being
    booked against the equity component of convertible debentures. This
    change did not have an impact on the September 30, 2010 statement of
    financial position as the convertible debentures were not issued until
    December 31, 2010.
h.  IAS 12 Adjustments - Income Taxes. The aforementioned changes increased
    (decreased) the net deferred tax liability as follows based on a tax
    rate of 25 percent:

                                                              September 30,
                                                                       2010
Impairment of plant, property and equipment (note 16b)     $        (44,892)
Depletion and depreciation (note 16c)                                 6,050
Decommissioning obligation (note 16d)                                (3,279)
Other adjustments (note 16c)                                           (361)
                                                            ----------------
Decrease in deferred tax liabilities                       $        (42,482)
----------------------------------------------------------------------------

IFRS requires that adjustments to the future tax rates used to calculate deferred taxes be traced and recorded against the original source of the timing difference as opposed to through earnings as was done under Canadian GAAP. As a result of this change at January 1, 2010, the Company reclassified $0.5 million in deferred taxes previously recorded in income against share issue costs.

The effect on the consolidated statements of operations and comprehensive loss for the three and nine months ended September 30, 2010 was to decrease the previously reported tax charge for the period by $10.2 million and $21.9 million respectively.


i.  Retained Earnings Adjustments. The aforementioned changes increased
    (decreased) increased retained earnings as follows on an after-tax
    basis:

                                                              September 30,
                                                                       2010
Impairment of plant, property and equipment (note 16b)     $       (133,270)
Decommissioning obligations (note 16d)                               (9,841)
Flow through shares (note 16f)                                       (5,336)
Depletion and depreciation (note 16c)                                17,993
Gain on sale of plant, property and equipment (note
 16c)                                                                   320
Deferred taxes on share issue costs (note 16h)                          449
General and administrative expenses (note 16c)                         (323)
Stock-based compensation (note 16e)                                     (78)
                                                            ----------------
Decrease in retained earnings                              $       (130,086)
----------------------------------------------------------------------------

j.  Adjustments to the Company's Cash Flow Statements under IFRS. The
    reconciling items discussed above between Canadian GAAP and IFRS
    policies have no material impact on the cash flows generated by the
    Company. As a result of the change in capitalized general and
    administrative expenses, there was a reduction of $0.4 million to
    operating cash flows, with and equal and opposite effect on investing
    cash flows for the nine months ended September 30, 2010 and $0.2 million
    for the three months ended September 30, 2010.

Directors

J.C. Anderson

Calgary, Alberta

Brian H. Dau

Calgary, Alberta

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

Calgary, Alberta

Glenn D. Hockley (1)(3)

Calgary, Alberta

David J. Sandmeyer (2)(3)

Calgary, Alberta

David G. Scobie (1)(2)

Calgary, Alberta

Member of:

(1) Audit Committee

(2) Compensation & Corporate

Governance Committee

(3) Reserves Committee

Auditors

KPMG LLP

Independent Engineers

GLJ Petroleum Consultants

Legal Counsel

Bennett Jones LLP

Registrar & Transfer Agent

Valiant Trust Company

Stock Exchange

The Toronto Stock Exchange

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

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

GJ - gigajoule

Mcf - thousand cubic feet

Mcfd - thousand cubic feet per day

MMcf - million cubic feet

MMcfd - million cubic feet per day

NGL - natural gas liquids

WTI - West Texas Intermediate

Contact Information

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

    Anderson Energy Ltd.
    700 Selkirk House, 555 4th Avenue S.W.
    Calgary, Alberta, Canada T2P 3E7
    (403) 262-6307
    (403) 261-2792 (FAX)
    www.andersonenergy.ca