Anderson Energy Ltd.
TSX : AXL

Anderson Energy Ltd.

November 15, 2010 17:00 ET

Anderson Energy Announces 2010 Third Quarter Results

CALGARY, ALBERTA--(Marketwire - Nov. 15, 2010) - Anderson Energy Ltd. ("Anderson Energy" or the "Company") (TSX:AXL) is pleased to announce its operating and financial results for the three and nine months ended September 30, 2010.

Repositioning for oil production growth continues to be the primary focus of the Company in light of the current and projected weakness in natural gas pricing. As detailed in the following discussion, oil production from the Cardium horizontal oil drilling program initiated this summer is coming on stream in the fourth quarter. The Company is making progress in its efforts to acquire additional Cardium acreage and implement drilling and completion initiatives to lower costs and improve well productivity and reserves.

HIGHLIGHTS:

- As of November 15, 2010, the Company has drilled 20 gross (13.5 net) Cardium horizontal oil wells with a 100% success rate, of which 16 gross (11.0 net) wells have been placed on production. In addition, the Company has two gross (1.0 net) Cardium wells producing back completion fluid that are expected to add new oil production before December. The Company has two gross (1.5 net) Cardium wells scheduled to be completed this week. The Company expects to be active in the field with two rigs drilling Cardium horizontal oil wells until spring breakup. The Company has increased its Cardium drilling plans for 2010 and now estimates it will drill 24 gross (17.2 net) Cardium horizontal wells in 2010.

- Third quarter production was 7,292 BOED, down 6% from the second quarter of 2010 due to extremely wet weather that delayed the Company's Cardium and Westpem projects. The Company started to ramp up its Cardium production in the third week of October and estimates average October production was approximately 8,300 BOED with new Cardium wells coming on stream in the third week of October. In the fourth quarter of 2010, oil and NGL production is estimated to be 25% of total production and 50% of total revenue at currently forecast prices. New oil production is brought on stream at significantly higher netbacks than natural gas.

- The Company's Cardium prospective land is 94 gross (53.6 net) sections. Based on a drilling density of three wells per section, the drilling inventory is potentially 282 gross (161 net) Cardium horizontal oil wells. The Company has advanced 80 gross (48.0 net) drilling locations which have been drilled or are planning to be drilled in the Garrington, Pembina, Willesden Green and Ferrier areas. The Company's exposure in the Cardium oil horizontal play has the potential to significantly increase future oil production.

- In the second half of 2010, the Company drilled two gross (2.0 net) and recompleted four gross (4.0 net) existing wells in Westpem. This production came on stream late in the third quarter of 2010 and early in the fourth quarter of 2010. Current production is 1,200 BOED, up substantially from the first quarter average of 700 BOED.

- On October 25, 2010, the Company announced an extension of the commitment date to drill the remaining 74 wells under an Edmonton Sands farm-in agreement from December 31, 2010 to March 31, 2012.

- In November 2010, the Company completed the semi-annual review of its borrowing base with its bankers and entered into an agreement with its syndicate of banks to increase its total available credit facilities from $115 million to $125 million, subject to completion of customary loan documentation.



FINANCIAL AND OPERATING HIGHLIGHTS

Three months ended Nine months ended
September 30 September 30
(thousands of dollars,
unless otherwise % %
stated) 2010 2009 Change 2010 2009 Change

Oil and gas
revenue before
royalties $ 18,928 $ 14,617 29% $ 62,511 $ 56,554 11%
Funds from
operations $ 8,026 $ 6,623 21% $ 27,665 $ 22,107 25%
Funds from
operations per
share
Basic $ 0.05 $ 0.04 25% $ 0.16 $ 0.19 (16%)
Diluted $ 0.05 $ 0.04 25% $ 0.16 $ 0.19 (16%)

Net loss $ (9,046) $ (9,432) 4% $(23,890) $(30,001) 20%
Net loss per
share
Basic $ (0.05) $ (0.06) 17% $ (0.14) $ (0.26) 46%
Diluted $ (0.05) $ (0.06) 17% $ (0.14) $ (0.26) 46%
Capital
expenditures,
including
acquisitions
net of
dispositions $ 39,528 $ 6,571 502% $ 85,700 $ 22,246 285%

Debt, net of
working capital $102,198 $ 69,819 46%

Shareholders'
equity $340,802 $338,746 1%

Average shares
outstanding
(thousands)
Basic 172,400 150,500 15% 169,569 116,470 46%
Diluted 172,400 150,500 15% 169,569 116,470 46%
Ending shares
outstanding
(thousands) 172,400 150,500 15%

Average daily
sales:
Natural gas
(Mcfd) 35,778 36,282 (1%) 36,668 39,685 (8%)
Liquids (bpd) 1,329 1,013 31% 1,231 1,166 6%
Barrels of oil
equivalent
(BOED) 7,292 7,060 3% 7,342 7,780 (6%)

Average prices:
Natural gas
($/Mcf) $ 3.43 $ 2.81 22% $ 4.12 $ 3.85 7%
Liquids ($/bbl) $ 58.61 $ 53.84 9% $ 60.32 $ 46.19 31%
Barrels of oil
equivalent
($/BOE) (1) $ 28.21 $ 22.50 25% $ 31.19 $ 26.63 17%

Royalties
($/BOE) $ 2.48 $ 1.24 100% $ 3.37 $ 3.07 10%
Operating costs
($/BOE) $ 9.71 $ 7.72 26% $ 10.15 $ 9.45 7%
Operating netback
($/BOE) $ 16.02 $ 13.54 18% $ 17.67 $ 14.11 25%
General and
administrative
($/BOE) $ 2.82 $ 2.18 29% $ 2.77 $ 2.39 16%

Wells drilled
(gross) 14 - 100% 43 11 291%

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


OPERATIONS

Cardium Horizontal Oil. In the third quarter of 2010, the Company drilled 11 gross (8.0 net) Cardium horizontal oil wells. Year to date, the Company has drilled 20 gross (13.5 net) Cardium horizontal oil wells. In September 2010, the Company had 4.0 net wells producing. Today, the Company has 11.0 net wells producing with 2.5 net new wells expected to be on stream prior to year end. On October 25, 2010, the Company announced that its Cardium production was approximately 1,300 BOED. To that point in time, the Company had spent approximately $40 million on the Cardium program. The Company has increased its Cardium drilling plans for 2010 and now estimates it could drill 24 gross (17.2 net) Cardium horizontal oil wells in 2010. A summary of the Company's Cardium horizontal well activity to date in 2010 is shown below:





Producing Drilled Remaining
Back and Total to to be
On Completion Completion November drilled
Area production Fluid Scheduled 15, 2010 in 2010
Gross Net Gross Net Gross Net Gross Net Gross Net
Garrington 7 5.8 1 0.6 2 1.5 10 7.9 2 1.9
Pembina East 4 3.9 - - - - 4 3.9 - -
Willesden Green 1 0.5 1 0.4 - - 2 0.9 2 1.8
Pembina West 4 0.8 - - - - 4 0.8 - -
------------------------------------------------------------
Total 16 11.0 2 1.0 2 1.5 20 13.5 4 3.7
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"Net" is net revenue interest earned.


The Company's Cardium prospective land inventory is 94 gross (53.6 net) sections. Based on a development drilling density of three wells per section, it could potentially drill 282 gross (161 net) Cardium horizontal wells. From this location list, the Company has advanced 80 gross (48.0 net) locations to be drilled in the next few years (including wells drilled to date). Each location to be drilled is technically feasible and is not contingent upon the drilling of other wells. Successful drilling of these wells and wells being drilled by third parties offsetting the Company's lands will add to this list of locations. The Company continues to explore opportunities to increase its land position in the play through acquisitions and farm-ins in its existing areas of focus and to improve operating efficiencies in the drilling and completion of wells. A more detailed discussion and review of the Company's Cardium drilling program and go forward plans is shown in the Company's investor presentation at www.andersonenergy.ca.

Edmonton Sands. The Company announced a 200 well Edmonton Sands farm-in commitment on January 29, 2009. Last winter, the Company drilled 126 wells and was planning to drill the remaining 74 wells by the commitment date of December 31, 2010. The terms of the farm-in agreement have been modified to extend the commitment date to March 31, 2012. With weak natural gas prices, the Company has decided to defer the drilling of the remaining 74 wells past 2010. On September 30, 2010, the Company completed the tie-in of the Medicine River compressor upgrade project with the tie-in of 9 gross (5.8 net) wells. This project had been delayed due to regulatory issues. The Company currently estimates its Edmonton Sands behind pipe connectable production to be approximately 1,400 BOED. With weak natural gas prices, the Company is deferring any further well tie-ins.

Westpem. In the second half of 2010, the Company drilled two gross (2.0 net) wells and recompleted four gross (4.0 net) existing wells in Westpem. This production came on stream late in the third quarter of 2010 and early in the fourth quarter of 2010. Current production is 1,200 BOED, up substantially from the first quarter average of 700 BOED.

PRODUCTION

Third quarter production was 7,292 BOED, down 6% from the second quarter of 2010 due to extremely wet weather that delayed the Company's Cardium and Westpem projects. The Company started to ramp up its Cardium production in the third week of October and estimates average October production was approximately 8,300 BOED. In the fourth quarter of 2010, oil and NGL production is expected to be 25% of total production and 50% of total revenue at currently forecast prices.

The Medicine River compressor upgrade project which had been delayed due to regulatory issues commenced production on September 30, 2010.

As a result of the delays in the second quarter of 2010, and the continuation of wet weather into the third quarter of 2010, the Company now estimates that 2010 annual production will be at the lower end of its previously stated guidance of 7,700 to 8,200 BOED in 2010. While production came on later than originally forecast, the program was successful and management is pleased with the initial performance from the wells. The Company estimates it will exit 2010 with production of approximately 8,700 to 9,000 BOED.

FINANCIAL RESULTS

Capital expenditures, net of dispositions were $39.5 million in the third quarter of 2010 with $30.5 million spent on drilling and completions and $7.9 million spent on facilities as compared to capital expenditures of $6.6 million in the third quarter of 2009.

The Company's funds from operations were $8.0 million in the third quarter of 2010 compared to $6.6 million in the third quarter of 2009. The Company's average natural gas sales price was $3.43 per Mcf in the third quarter of 2010 compared to $2.81 per Mcf in third quarter of 2009. The Company's average crude oil and natural gas liquids sales price in the third quarter of 2010 was $58.61 per barrel compared to $53.84 per barrel in the third quarter of 2009. WTI oil prices averaged $76.20 US per barrel in the third quarter of 2010. The Company's operating netback was $17.67 per BOE in the first nine months of 2010 compared to $14.11 per BOE in the comparable period of 2009. The increase in the operating netback was primarily due to the increase in commodity prices. Operating expenses in the third quarter of 2010 were $9.71 per BOE. Start up costs associated with new Cardium production, various production optimization initiatives undertaken in September and a large one time compressor repair cost at Buck Lake offset some of the savings associated with the Edmonton Sands lower operating cost gas production in the third quarter of 2010.

FINANCING

In November 2010, the Company completed the semi-annual review of its borrowing base with its bankers and entered into an agreement with its syndicate of banks to increase its total available credit facilities from $115 million to $125 million, subject to completion of customary loan documentation.

In October 2010, the Company entered into fixed price swaps for 1,000 barrels per day of crude oil for December 2010 at a NYMEX crude oil price of Canadian $85.70 per barrel for December 2010 and for calendar 2011 at a NYMEX crude oil price of Canadian $88.45 per barrel.

In the third quarter of 2010, the Company sold $1.2 million in surplus drilling royalty credits and minor properties. In the fourth quarter of 2010 the Company has entered into agreements to sell $0.8 million of surplus drilling royalty credits and minor properties.

The Company is expected to spend $110 million, net of dispositions in 2010. The Company is planning to drill 24 gross (17.2 net) Cardium horizontal wells in 2010.

OUTLOOK

Natural gas prices were weak in the second and third quarters of 2010 and the outlook for the upcoming winter is not encouraging. The low natural gas prices are a result of United States drilling rig counts remaining high in the face of an uneconomic future NYMEX strip natural gas price. Industry analysts attribute the high United States rig counts to drilling for lease retention purposes in shale gas plays. These same analysts also expect the pace of lease retention to lessen in the second half of 2011. Until the United States rig count and natural gas supply decreases, the price of natural gas will be suppressed. While the return of winter may help somewhat to strengthen natural gas prices, the Company's response to the current weak natural gas market is to switch its capital spending to horizontal oil drilling. New crude oil production is brought on stream at significantly higher netbacks than natural gas. Consequently, cash flow can be increased at a proportionately greater rate for the same level of production growth. The Company has the flexibility and the prospects to conduct a 2011 capital program which could be focused almost 100% on oil. The Company will be releasing 2011 guidance in January 2011. With an oil only capital program, preliminary modeling indicates the Company could increase its oil and NGL percentage of total production from 19% in 2010 to 35% in 2011 and could exit 2011 at approximately 45% on a BOED basis.

The Alberta government has made important changes to their fiscal incentives program which benefit the Company. The 5% one year royalty program has now been made permanent. Other important changes positively impact the Company's Cardium horizontal oil program. 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. The Alberta government has reduced the maximum gas royalty from 50% to 36% and the maximum oil royalty from 50% to 40%. In addition, the Alberta government has reduced the depth requirement from 2,500 to 2,000 meters to qualify for the natural gas deep drilling program, which benefits the Company's Westpem and Willesden Green deep gas drilling programs.

The Company is focused on its Cardium oil horizontal program and is also pursuing horizontal oil opportunities in the Belly River, Viking and other potential oil zones. The impact of the Company's repositioning to oil production growth will start to be felt in the fourth quarter of 2010. The Company is advancing its Cardium drilling plans in 2010, looking to add to its Cardium prospective land inventory and drilling locations through acquisitions and farm-ins, and implementing newer Cardium drilling and completion technologies to lower costs and improve productivity and reserves. These initiatives are designed to advance the Company's transition to oil production growth.

Brian H. Dau, President & Chief Executive Officer

November 15, 2010

Management's Discussion and Analysis

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2010 AND 2009

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 Energy" or the "Company") for the three and nine months ended September 30, 2010 and the audited consolidated financial statements and management's discussion and analysis of Anderson Energy for the years ended December 31, 2009 and 2008 and is based on information available as of November 15, 2010.

The following information is based on financial statements prepared by management in accordance with Canadian generally accepted accounting principles ("GAAP"). 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 asset retirement 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 and operating 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 Canadian GAAP 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, 2010, funds from operations were $8.0 million, up 21% from the third quarter of 2009 due to higher commodity prices and higher production levels. For the nine month period ended September 30, 2010, funds from operations were $27.7 million, up 25% from the comparable period in 2009.

Sales volumes for the three months ended September 30, 2010 averaged 7,292 BOED compared to 7,060 BOED in 2009 and 7,732 BOED in the second quarter of 2010. Sales volumes were 6% lower than the second quarter of 2010 due to extremely wet weather that delayed the Company's Cardium horizontal light oil and Westpem deep gas projects. Normal new production declines from gas wells tied in earlier in the year also impacted sales volumes. Natural gas prices declined in the third quarter of 2010, which combined with lower production, resulted in lower funds from operations compared to the second quarter of 2010.

Capital additions, net of dispositions were $39.5 million for the three months ended September 30, 2010. During the third quarter of 2010, the Company drilled 11 gross (8.0 net) Cardium horizontal light oil wells, two gross (2.0 net) Rock Creek deep gas wells and one gross (0.5 net) Ellerslie deep gas well with a 100% success rate. The Company tied in 10 gross (6.0 net) Edmonton Sands shallow gas wells, two gross (2.0 net) Rock Creek deep gas wells and four gross (2.0 net) Cardium horizontal light oil wells in the third quarter of 2010.

Debt, net of working capital, was $102.2 million at September 30, 2010 and reflects the large capital program conducted late in the third quarter. As a result of the reduction in natural gas prices, the Company has refocused its capital expenditure program on crude oil prospects. As this new crude oil production is brought on stream at higher expected operating margins, funds from operations are expected to increase.

Revenue and Production. Gas sales comprised 82% of Anderson Energy's total oil and gas sales volumes for the three months ended September 30, 2010, which is a slightly lower percentage than in the second quarter of 2010, reflecting normal new production declines in natural gas and increased oil production. The Company is refocusing on horizontal oil drilling in the remainder of 2010 and into 2011 as a result of the weak natural gas price environment. The Company's production volumes are expected to start shifting more significantly towards oil and NGL volumes starting in the fourth quarter of 2010.

Gas sales volumes for the three months ended September 30, 2010 were 35.8 MMcfd compared to 39.0 MMcfd in the second quarter of 2010 and 36.3 MMcfd in the same period in 2009. Gas sales for the nine months ended September 30, 2010 were 36.7 MMcfd compared to 39.7 MMcfd for the nine months ended September 30, 2009. The Company reduced capital spending in 2009 due to market conditions, and then in 2010, began to shift the focus of its capital spending to oil prospects.

Oil sales for the three months ended September 30, 2010 averaged 568 bpd compared to 491 bpd in the second quarter of 2010 and 376 bpd for the third quarter of 2009. The increase in volumes from the second quarter of 2010 is due to new oil production, including three gross (1.6 net) Cardium horizontal light oil wells which were not brought on stream until September 2010. There were no oil wells drilled in 2009.

Natural gas liquids sales for the three months ended September 30, 2010 averaged 761 bpd compared to 741 bpd in the second quarter of 2010 and 637 bpd for the third quarter of 2009. Natural gas liquids volumes increased due to the tie-in of two gross (2.0 net) Rock Creek deep gas wells in the third quarter of 2010.

The following tables outline production revenue, volumes and average sales prices for the period ended September 30, 2010 and 2009.



OIL AND NATURAL GAS REVENUE
Three months ended Nine months ended
September 30, 2010 September 30
(thousands of dollars) 2010 2009 2010 2009
Natural gas $ 11,304 $ 9,390 $ 39,984 $ 41,672
Gain on fixed price natural gas
contracts - - 1,302 -
Oil 3,567 2,398 9,061 6,293
NGL 3,598 2,619 11,213 8,402
Royalty and other 459 210 951 187
----------------------------------------
Total $ 18,928 $ 14,617 $ 62,511 $ 56,554
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PRODUCTION
Three months ended Nine months ended
September 30 September 30
2010 2009 2010 2009
Natural gas (Mcfd) 35,778 36,282 36,668 39,685
Oil (bpd) 568 376 469 410
NGL (bpd) 761 637 762 756
----------------------------------------
Total (BOED) 7,292 7,060 7,342 7,780
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PRICES
Three months ended Nine months ended
September 30 September 30
2010 2009 2010 2009
Natural gas ($/Mcf) (1) $ 3.43 $ 2.81 $ 4.12 $ 3.85
Oil ($/bbl) 68.24 69.30 70.77 56.27
NGL ($/bbl) 51.41 44.70 53.89 40.73
----------------------------------------
Total ($/BOE) (2) $ 28.21 $ 22.50 $ 31.19 $ 26.63
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(1) Nine month price includes gain on fixed price natural gas contracts from
the first quarter of 2010.
(2) Includes royalty and other income classified with oil and gas sales.


Anderson Energy's average natural gas sales price was $3.43 per Mcf for the three months ended September 30, 2010, 9% lower than the second quarter of 2010 price of $3.78 per Mcf and 22% higher than the third quarter of 2009 price of $2.81 per Mcf. Anderson Energy's average gas sales price was $4.12 per Mcf for the nine months ended September 30, 2010. The natural gas price in the first quarter of 2010 included a gain of $1.3 million on the Company's fixed price natural gas contracts. The gas price before the gain was $3.99 per Mcf in the first nine months of 2010 and $4.81 per Mcf for the first quarter of 2010. Gas prices have been significantly affected by increased supply and lower industrial consumption of natural gas in the United States and continue to be weak into the fourth quarter of 2010.

Historically, Anderson Energy has sold most of its gas at Alberta spot market prices. The Company is currently selling gas production at the average daily index price. The Company has classified all 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 31 MMcfd of natural gas sales for various terms ranging from one to ten years. Crude oil transportation costs are currently being classified with operating expenses.

Fixed Price Contracts. In December 2009, 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 20,000 GJ per day of natural gas for each of January, February and March 2010 at an average AECO price of $5.41 per GJ. The Company realized a gain on fixed price natural gas contracts of $1.3 million for the nine months ended September 30, 2010. The Company had no fixed price contracts in place as at September 30, 2010.

In October 2010, the Company entered into fixed price swaps for 1,000 barrels per day of crude oil for December 2010 at a NYMEX crude oil price of Canadian $85.70 per barrel and for calendar 2011 at a NYMEX crude oil price of Canadian $88.45 per barrel.

Royalties. Royalties were 8.8% of revenue for the three months ended September 30, 2010 compared to 8.3% for the second quarter of 2010 and 5.5% for the three months ended September 30, 2009. On January 1, 2009, the Alberta government's New Royalty Framework came into effect. While royalties increased in some areas, overall, the changes reduced royalties. In addition, when prices and corresponding revenues are lower, fixed monthly gas cost allowance becomes more significant to the overall royalty rate. Royalties as a percentage of revenue are highly sensitive to prices and adjustments to gas cost allowance and so these rates can fluctuate from quarter to quarter. The Alberta government revised the royalty regime in March 2009, and again in March 2010, for new wells tied in on Crown lands. 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, the Alberta government changed the maximum royalty payable on oil from 50% to 40% and on natural gas from 50% to 36%. Other important changes positively impact the Company's refocused horizontal oil program, where 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
2010 2009 2010 2009
Gross Crown royalties 12.0% 10.5% 13.0% 15.5%
Gas cost allowance (8.9%) (12.9%) (8.5%) (11.2%)
Other royalties 5.7% 7.9% 6.3% 7.2%
-----------------------------------------
Royalties 8.8% 5.5% 10.8% 11.5%
Royalties ($/BOE) $ 2.48 $ 1.24 $ 3.37 $ 3.07
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----------------------------------------------------------------------------


Operating Expenses. Operating expenses were $9.71 per BOE for the three months ended September 30, 2010 compared to $9.89 per BOE in the second quarter of 2010. Operating expenses were $10.15 per BOE for the nine months ended September 30, 2010 compared to $9.45 per BOE in the first nine months of 2009. Start up costs associated with new Cardium production, various production optimization initiatives undertaken in September and a large one time compressor repair cost at Buck Lake offset some of the cost savings associated with the Edmonton Sands lower operating cost gas production in the third quarter of 2010.



OPERATING NETBACK

Three months ended Nine months ended
September 30 September 30
(thousands of dollars) 2010 2009 2010 2009
Revenue $ 18,928 $ 14,617 $ 62,511 $ 56,554
Royalties (1,665) (804) (6,755) (6,522)
Operating expenses (6,515) (5,013) (20,349) (20,075)
------------------------------------------
$ 10,748 $ 8,800 $ 35,407 $ 29,957
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----------------------------------------------------------------------------
Sales (MBOE) 670.9 649.5 2,004.5 2,123.8

Per BOE
Revenue (1) $ 28.21 $ 22.50 $ 31.19 $ 26.63
Royalties (2.48) (1.24) (3.37) (3.07)
Operating expenses (9.71) (7.72) (10.15) (9.45)
------------------------------------------
$ 16.02 $ 13.54 $ 17.67 $ 14.11
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes royalty and other income classified with oil and gas sales.


General and Administrative Expenses. General and administrative expenses were $1.9 million or $2.82 per BOE for the three months ended September 30, 2010 compared to $1.9 million or $2.77 per BOE in the second quarter of 2010 and $1.4 million or $2.18 per BOE for the three months ended September 30, 2009. General and administrative expenses were $5.6 million or $2.77 per BOE for the nine months ended September 30, 2010 compared to $5.1 million or $2.39 per BOE for the first nine months of 2009. Additional staff were hired in 2010 as a result of increased activity. The Company also reversed certain salary cutbacks previously taken and reinstated its employee stock savings plan effective April 1, 2010.



Three months ended Nine months ended
September 30 September 30
(thousands of dollars) 2010 2009 2010 2009
General and administrative (gross) $ 3,347 $ 2,685 $ 9,660 $ 9,008
Overhead recoveries (411) (573) (1,181) (1,284)
Capitalized (1,042) (697) (2,919) (2,641)
-----------------------------------------
General and administrative (net) $ 1,894 $ 1,415 $ 5,560 $ 5,083
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----------------------------------------------------------------------------
General and administrative ($/BOE) $ 2.82 $ 2.18 $ 2.77 $ 2.39
% Capitalized 31% 26% 30% 29%
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----------------------------------------------------------------------------


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

Stock-Based Compensation. The Company accounts for stock-based compensation plans using the fair value method of accounting. Stock-based compensation costs were $0.9 million for the third quarter of 2010 ($0.5 million net of amounts capitalized) versus $0.7 million ($0.3 million net of amounts capitalized) in the third quarter of 2009. Stock-based compensation costs were $1.7 million for the first nine months of 2010 ($0.9 million net of amounts capitalized) versus $1.7 million ($0.9 million net of amounts capitalized) in the first nine months of 2009. The increase is a result of new options issued in the third quarter of 2010 offset partially by some options reaching their full vesting terms and some options being forfeited.

Interest Expense. Interest expense was $0.8 million for the third quarter of 2010, compared to $0.7 million in the second quarter of 2010 and $0.8 million in the third quarter of 2009. The slight increase in interest expense from the second quarter of 2010 is due to the higher average debt levels. For the nine months ended September 30, 2010, interest expense was $2.3 million compared to $2.9 million for the first nine months of 2009. The decrease in interest expense from the comparable 2009 period is due to lower average debt levels in the first nine months of 2010 partially offset by increases in interest rates. The average effective interest rate on outstanding bank loans was 4.9% for the nine months ended September 30, 2010 compared to 4.2% for the nine months ended September 30, 2009.

Depletion and Depreciation. Depletion and depreciation was $18.9 million ($28.23 per BOE) for the third quarter of 2010 compared to $19.9 million ($28.23 per BOE) in the second quarter of 2010 and $18.9 million ($29.09 per BOE) in the third quarter of 2009. Depletion and depreciation was $56.5 million ($28.18 per BOE) for the first nine months of 2010 compared $61.4 million ($28.92 per BOE) for the comparable period in 2009. Decreased production in the third quarter of 2010 resulted in lower depletion and depreciation expense when compared to the second quarter of 2010.

Asset Retirement Obligation. The Company recorded a $0.2 million increase in asset retirement obligations in the third quarter of 2010 related to current activity and changes in estimates. Accretion expense was $0.7 million for the third quarter of 2010 compared to $0.5 million in the third quarter of 2009 and was included in depletion and depreciation expense.

Income Taxes. Anderson Energy is not currently taxable. The Company does not anticipate paying current income tax in 2010. The future income tax reduction has decreased as a percentage of pre-tax loss due to lower corporate tax rates. The Company has approximately $370 million in tax pools at September 30, 2010.

Funds from Operations. Funds from operations for the third quarter of 2010 were $8.0 million ($0.05 per share), 21% higher than the $6.6 million ($0.04 per share) recorded in the same period of 2009. This compares to funds from operations in the second quarter of 2010 of $9.0 million ($0.05 per share). Funds from operations for the first nine months of 2010 were $27.7 million ($0.16 per share) compared to $22.1 million ($0.19 per share) recorded in the same period of 2009. Funds from operations are significantly impacted by fluctuating commodity prices, particularly for natural gas, and the corresponding impact on capital spending and production levels. Cash from operating activities is similarly affected. As a result of the decline in natural gas prices, the Company has refocused its capital expenditure program on crude oil prospects. As this new crude oil production is brought on stream at significantly higher expected operating margins, funds from operations are expected to increase at a proportionately greater rate than overall production volume growth.



Three months ended Nine months ended
September 30 September 30
(thousands of dollars) 2010 2009 2010 2009
Cash from operating activities $ 8,437 $ 6,689 $ 30,275 $ 18,459
Changes in non-cash working capital (823) (66) (4,041) 2,710
Asset retirement expenditures 412 - 1,431 938
----------------------------------------
Funds from operations $ 8,026 $ 6,623 $ 27,665 $ 22,107
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Earnings. The Company reported a net loss of $9.0 million in the third quarter of 2010 compared to a net loss of $8.9 million for the second quarter of 2010 and a net loss of $9.4 million for the third quarter of 2009. The Company reported a net loss of $23.9 million in the first nine months of 2010 compared to a net loss of $30.0 million in the first nine months of 2009. As with funds from operations, earnings continue to be impacted by low natural gas prices. The change in the Company's focus to crude oil, with its currently higher operating margins, is expected to improve earnings.

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
Per Per
(thousands of dollars) Millions Share Millions Share
$0.50/Mcf in price of natural gas $ 7.2 $ 0.06 $ 5.1 $ 0.04
US $5.00/bbl in the WTI crude price $ 1.8 $ 0.01 $ 1.3 $ 0.01
US $0.01 in the US/Cdn exchange rate $ 0.7 $ 0.01 $ 0.5 $ 0.00
1% in short-term interest rate $ 0.8 $ 0.01 $ 0.5 $ 0.00
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This sensitivity analysis was calculated by applying different pricing, interest rate and exchange rate assumptions to the 2009 actual results related to production, prices, 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 $39.5 million on capital additions, net of dispositions in the third quarter of 2010. The breakdown of expenditures is shown below:



Three months ended Nine months ended
September 30 September 30
(thousands of dollars) 2010 2009 2010 2009
Land, geological and geophysical
costs $ 28 $ 51 $ 427 $ 188
Acquisitions, net of dispositions 513 - (763) (54)
Drilling, completion and recompletion 30,548 1,580 53,537 8,460
Drilling incentive credits (1,003) - (3,617) -
Facilities and well equipment 7,910 1,226 33,782 7,707
Capitalized G&A 1,042 697 2,919 2,641
----------------------------------------
Total finding, development &
acquisition expenditures 39,038 3,554 86,285 18,942
Change in compressor and other
equipment inventory 480 3,009 (644) 3,278
Office equipment and furniture 10 8 59 26
----------------------------------------
Total capital expenditures 39,528 6,571 85,700 22,246
Non-cash asset retirement obligations
and capitalized stock-based
compensation 603 (151) 1,865 1,217
----------------------------------------
Total cash and non-cash capital
additions $ 40,131 $ 6,420 $ 87,565 $ 23,463
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Drilling statistics are shown below:

Three months ended Nine months ended September 30
2010 2009 2010 2009
Gross Net Gross Net Gross Net Gross Net
Gas 3 2.5 - - 23 19.0 11 8.3
Oil 11 8.0 - - 16 11.2 - -
Dry - - - - 4 2.8 - -
--------------------------------------------------------
Total 14 10.5 - - 43 33.0 11 8.3
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Success rate (%) 100% 100% - - 91% 92% 100% 100%
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"Net" is net capital interest.


In the third quarter of 2010, the Company drilled 11 gross (8.0 net) Cardium horizontal light oil wells, two gross (2.0 net) Rock Creek deep gas wells and one gross (0.5 net) Ellerslie deep gas well. The Company did not drill any vertical Edmonton Sands shallow gas wells in the third quarter of 2010. The Company tied in 10 gross (6.0 net) Edmonton Sands shallow gas wells, two gross (2.0 net) Rock Creek deep gas wells and four gross (2.0 net) Cardium horizontal light oil wells. Approximately $1.2 million was spent on shallow gas fit for purpose processing facilities in the Medicine River area, which went online on September 30, 2010. The Company did not drill any wells during the third quarter of 2009.

In the fourth quarter of 2009, the Company accrued $6.0 million for drilling incentive credits. Drilling credits earned are capped at 50% of crown royalties paid between April 1, 2009 and March 31, 2011 and the Company estimates that it will earn more drilling credits than it will be able to claim. These credits are expected to be paid out between 2009 and 2011 as crown royalties are paid. The estimate is highly dependent on commodity prices, production levels, crown royalty rates and gas cost allowance earned over this period. To the extent that crown royalties paid are lower or higher, drilling credits will be lower or higher as well. As a result of the cap, no additional credits were accrued related to drilling in the first nine months of 2010. The Company received $3.6 million in proceeds on the sale of some of these surplus credits in the nine months ended September 30, 2010 and has signed agreements for the sale of additional surplus credits amounting to $0.8 million subsequent to the end of the period.

CEILING TEST

No impairment was recognized under the ceiling test at September 30, 2010. The future commodity prices used in the ceiling test were based on the commodity price forecasts of the Company's independent reserves engineers at October 1, 2010 adjusted for differentials specific to the Company's reserves. These price forecasts have declined since year end which has had the impact of reducing the available cushion under the ceiling test. This has been offset by increases in the Company's oil reserves. Factors used in the ceiling test calculation are disclosed in note 1 of the consolidated interim financial statements for the period ended September 30, 2010.

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 15, 2010, there were 172.5 million common shares outstanding and 12.5 million stock options outstanding.



Three months ended Nine months ended
September 30 September 30
2010 2009 2010 2009
High $ 1.24 $ 1.12 $ 1.57 $ 1.48
Low $ 0.95 $ 0.68 $ 0.95 $ 0.65
Close $ 1.12 $ 0.97 $ 1.12 $ 0.97
Volume 18,034,164 46,106,377 88,346,700 95,749,639
Shares outstanding at
September 30 172,400,401 150,500,401 172,400,401 150,500,401
Market capitalization
at September 30 $193,088,449 $145,985,389 $193,088,449 $145,985,389
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The statistics above include trading on the Toronto Stock Exchange only. Shares also trade on alternative platforms like Alpha, Chi-X, Pure and Omega. Approximately 8.5 million common shares traded on these alternative exchanges in the three months ended September 30, 2010.

LIQUIDITY AND CAPITAL RESOURCES

At September 30, 2010, the Company had outstanding long term bank loans of $67.8 million and a working capital deficiency of $34.4 million. Due to extremely wet weather that delayed the Company's Cardium horizontal light oil and Westpem deep gas projects until late in the quarter, the working capital deficiency includes a large accrual for capital expenditures incurred late in the quarter.

The Company's 2010 net capital expenditures are expected to be $110 million, of which $85.7 million was spent in the first nine months of 2010. The Company was originally committed to drill 74 Edmonton Sands gas wells under its farm-in agreement by December 31, 2010. In October 2010, the commitment date was revised from December 31, 2010 to March 31, 2012. The Company does not plan to drill any additional Edmonton Sands gas wells in 2010. The Company is planning to drill eight gross (7.0 net) Cardium oil wells in the fourth quarter of 2010.

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, 2010, the Company had total available credit facilities of $115 million, consisting of an $80 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. In November 2010, these facilities were increased to $125 million. The borrowing base was reaffirmed and the Company entered into an agreement with its syndicate of banks to increase the supplemental facility to $35 million, subject to completion of customary loan documentation. The supplemental facility supports the Cardium horizontal oil drilling program. Draws over $30 million under the supplemental facility will be subject to the consent of the syndicate at the time of the drawdown. Anderson Energy will prudently use its bank loan facilities to finance its operations as required. The available lending limits under the bank facilities are reviewed twice a year, with the next review scheduled for May 2011, and are based on the bank syndicate's interpretation of the Company's reserves and future commodity prices. There can be no assurance that the amount of the available bank lines will not be adjusted. The Company will continue to fund its ongoing operations from a combination of cash flow, debt, asset dispositions and equity financing as needed.

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 12, 2011, extendible at the option of the lenders. If not extended, the facilities cease to revolve and all outstanding advances thereunder become repayable in one year from the term date of July 12, 2011. The supplemental facility is available on a revolving basis and expires on July 1, 2011 with any amounts outstanding due in full at that time. No amounts were drawn under the supplemental facility at September 30, 2010.

- Lease for office space - This lease expires on November 30, 2012. Future minimum lease payments are expected to be $0.4 million for the remainder of 2010, $1.8 million in 2011, and $1.6 million in 2012.

- Firm service transportation commitments - The Company has entered into firm service transportation agreements for approximately 31 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 $0.6 million for the remainder of 2010, $2.2 million in 2011, $1.6 million in 2012, $0.9 million in 2013, $0.7 million in 2014 and $1.0 million thereafter.

- 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, 2010. The Company is obligated to complete the drilling of the remaining wells on or before March 31, 2012. 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 past 2010.

INTERNATIONAL FINANCIAL REPORTING STANDARDS ("IFRS")

In February 2008, the CICA Accounting Standards Board ("AcSB") confirmed the changeover to IFRS from Canadian Generally Accepted Accounting Principles ("GAAP") will be required for publicly accountable enterprises for interim and annual financial statements effective for fiscal years beginning on or after January 1, 2011, including comparatives for 2010.

In response, the Company has completed its high-level IFRS changeover plan and established a timeline for the execution and completion of the conversion project. The changeover plan was determined following a preliminary assessment of the differences between Canadian GAAP and IFRS and the potential effects of IFRS to accounting and reporting processes, information systems, business processes and external disclosures. This assessment has provided insight into what are anticipated to be the most significant areas of difference applicable to the Company.

The Company is performing an in-depth review of the significant areas of difference identified during the preliminary assessment, in order to identify all specific Canadian GAAP and IFRS differences and select ongoing IFRS policies. Key areas addressed will also be reviewed to determine any information technology issues, the impact on internal controls over financial reporting and the impact on business activities including the effect, if any, on covenants and compensation arrangements. External advisors have been retained and will assist management with the project on an as needed basis to ensure IFRS readiness upon transition.

Below is a summary of the Company's current views of the key areas where changes in accounting policies are expected that may impact the Company's consolidated financial statements. The list and comments below should not be regarded as a complete list of changes that will result from the transition to IFRS. It is intended to highlight those areas the Company believes to be most significant; however, analysis of changes is still in progress and not all decisions have been made where choices of accounting policies are available. At this stage, the Company has not quantified the impacts expected on its consolidated financial statements for these differences.

Note that most adjustments required on transition to IFRS will be made retrospectively, against opening retained earnings in the first comparative balance sheet. Transitional adjustments relating to those standards where comparative figures are not required to be restated because they are applied prospectively will only be made as of the first day of the year of transition.

IFRS 1 "First-Time Adoption of International Financial Reporting Standards" provides entities adopting IFRS for the first time with a number of optional exemptions and mandatory exceptions, in certain areas, to the general requirement for full retrospective application of IFRS. The Company is analyzing the various accounting policy choices available and will implement those determined to be the most appropriate in the Company's circumstances.

Property, Plant and Equipment. International Accounting Standard (IAS) 16 "Property, Plant & Equipment" and Canadian GAAP contain the same basic principles, however there are some differences. IFRS requires that significant parts of an asset be depreciated separately and depreciation commences when the asset is available for use. The Company has currently only identified one significant component to be depreciated separately as the majority of its assets are estimated to have useful lives tied to the reserves they service. IFRS also permits property, plant equipment to be measured using the fair value model or the historical cost model. The Company is not planning on adopting the fair value measurement model for property, plant and equipment.

Under the full cost accounting guideline in Canadian GAAP, gains or losses are not recognized upon the disposition of petroleum and natural gas ("P&NG") assets unless the disposition results in a significant change in the depletion rate. Under IFRS, gains and losses are recognized in net income on the disposal of an item of P&NG assets. The amount of the gain or loss is determined by comparing the proceeds from disposal with the carrying amount of the item. This will include transactions such as sales of assets, farm-outs, asset swaps and other non-monetary transactions which typically did not result in gains or losses being recorded under Canadian GAAP. The Company will be reviewing its 2010 disposition activity in order to determine the magnitude of the gain or loss required to be disclosed under IFRS.

IFRS 1 contains an exemption whereby a company may apply IFRS prospectively by utilizing its current reserves (volumes or values) at the transition date to allocate the Company's full cost pool, with the provision that an impairment test, under IFRS standards, be conducted at the transition date. The Company intends to use this exemption and is currently evaluating the impact of allocating the net book values based on reserve volumes or values.

Provisions. Under IFRS, similar to Canadian GAAP, the Company is required to record obligations relating to the retirement of its wells and facilities where a legal or contractual obligation currently exists. Upon the adoption of IFRS, the Company will also need to evaluate if there are any constructive obligations where the decommissioning liability would also need to be recognized. Currently, the Company has not identified any constructive obligations.

Upon transition, the Company intends to apply the IFRS 1 exemption whereby the decommissioning liability provision is recalculated at January 1, 2010 using the IFRS methodology and any adjustments would be offset against opening retained earnings.

The Company is in the process of recalculating its decommissioning liabilities under IFRS and is reviewing the calculation assumptions, including the future cash flows as well as the appropriateness of the discount rate. The magnitude of the transition adjustment will depend largely on the discount rate used. The discount rate will also continue to impact additions to decommissioning liabilities going forward under IFRS.

Impairment of Assets. IAS 36 "Impairment of Assets" requires that impairments be determined based on the greater of fair value and value in use. This differs from the current two step practice where the asset's carrying value is initially compared to the estimated undiscounted future cash flows, and only if the carrying value exceeds the undiscounted future cash flows is a discounted analysis, step two, required. There is no undiscounted test under IFRS. This may result in more frequent write-downs upon transition. The Company anticipates that there will be an impairment at transition as a result of weak natural gas prices in conjunction with a change in the impairment testing methodology. The Canadian GAAP impairment test is essentially a recoverability test as compared to a fair value test under IFRS. The magnitude of the impairment will vary depending upon the discount rate applied.

In addition, under IFRS, an entity must also evaluate whether there are changes in circumstances that would support an impairment reversal, which is not allowable under the full cost guideline under Canadian GAAP.

Another difference arises in the level at which an impairment test is performed. Under IFRS, impairment testing will be performed on cash generating units. The Company will have more cash generating units than the current single full cost pool under Canadian GAAP.

Income taxes. Under IAS 12 "Income Taxes", current and deferred tax are normally recognized in the income statement, except to the extent that tax arises from (1) an item that has been recognized directly in equity, whether in the same or a different period, (2) a business combination or (3) a share based payment transaction. If a deferred tax asset or liability is re-measured subsequent to initial recognition, the impact of re-measurement is recorded in earnings, unless it relates to an item originally recognized in equity, in which case the change would also be recorded in equity. The practice of tracking the re-measurement of taxes back to the item which originally triggered the recognition is commonly referred to as "backwards tracing". The Company is currently assessing the transitional impact of adopting this standard.

Share based payments. Under IFRS 2 "Share-Based Payments", graded vested options are required to be separated into their vesting tranches and valued and accounted for separately. This differs from Canadian GAAP, where graded vested options may be valued as a single award at the grant date and expensed using the straight line method. IFRS 1 provides an exemption for equity instruments which vested before the transition date and does not require them to be retroactively restated. All unvested options at transition date will be required to be retroactively restated with the adjustment going through opening retained earnings on transition. The Company intends to use this exemption and does not anticipate that there will be a significant impact on transition.

The Company continues to assess the impact of IFRS on its accounting systems, disclosure controls and internal controls and is designing, testing and implementing changes to its accounting systems as appropriate. The Company has not yet identified any material changes needed to its controls. However, it does anticipate that a significant amount of additional time and effort will be required to carry out controls during the implementation period and is budgeting accordingly. In the fourth quarter of 2010, the Company plans to commence drafting the new financial statement disclosures that will be required in its 2011 financial statements under IFRS.

The Company will also continue to monitor standards development as issued by the International Accounting Standards Board ("IASB") and the AcSB as well as regulatory developments as issued by the Canadian Securities Administrators, which may affect the timing, nature or disclosure of its adoption of IFRS.

In the third quarter of 2010, the Company's auditors started the review of policy choices made and the methodology used for transition adjustment calculations. The opening balance sheet audit is scheduled to be conducted early in 2011 after the Company has completed additional calculations and drafted additional disclosures.

CONTROLS AND PROCEDURES

The Chief Executive Officer and the Chief Financial Officer have evaluated and tested the effectiveness of Anderson Energy's disclosure controls and procedures as of September 30, 2010 and have concluded that such disclosure controls and procedures were effective.

The Chief Executive Officer and the Chief Financial Officer have evaluated and tested the design effectiveness of Anderson Energy's internal controls over financial reporting during the three months ended September 30, 2010 and have concluded that, these internal controls are designed properly and are effective in the preparation of financial statements for external purposes in accordance with Canadian GAAP. There were no material changes in the Company's internal controls over financial reporting during the three months ended September 30, 2010.

Because of inherent limitations, internal controls over financial reporting may not prevent or detect all misstatements, errors or fraud. Control systems, no matter how well designed, only provide reasonable, not absolute, assurance that the objectives of the controls systems are met.

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. Natural gas prices in particular have weakened on fears of reduced industrial use due to the continued U.S. recession and increased supply from U.S. natural gas shale plays. 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, 2009 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 Energy 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 Energy seeks out and employs new technologies where possible. With the Company's extensive drilling inventory and advance planning, the Company 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 new framework, the formula for conventional oil and natural gas royalties uses a sliding rate formula, dependant on the market price and production volumes. Royalty rates for conventional oil ranged from 0% to 50%. Natural gas royalty rates ranged from 5% to 50%.

On March 3, 2009, the Government of Alberta announced an incentive program for the energy sector. Amendments to the program were announced on June 11 and June 25, 2009. This incentive program includes a drilling credit for new oil and natural gas wells drilled between April 1, 2009 and March 31, 2011, providing a $200 per meter drilled royalty credit to companies. The credit is limited to 50% of Crown royalties payable over the same period. 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 additional amendments, which come into effect January 1, 2011. Under the most recent amendments, the maximum royalty paid was reduced from 50% to 40% on oil and from 50% to 36% on natural gas. The 5% front end royalty rate was extended for horizontal oil wells spud on or after May 1, 2010. Based on measured depth of the well, the 5% rate could be extended to 18 to 48 months on 50 Mstb to 100 Mstb of oil production. The majority of the Company's planned horizontal wells on Crown lands would qualify for 30 months of 5% royalty for up to 70 Mstb of oil production. In addition, the Alberta government has reduced the depth requirement from 2,500 to 2,000 meters to qualify for the natural gas deep drilling program, which benefits the Company's Westpem and Willesden Green deep gas drilling program. According to the announced amendments, the new well incentive program is to become a permanent feature to the new oil and gas royalty framework.

The 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 is currently focused on its Cardium horizontal oil program in its one core area in central Alberta and has deferred the development of its shallow gas play.

Anderson Energy has significant exposure to multistage frac opportunities in the Cardium light oil horizontal play. The Company has 94 gross (53.6 net) sections in the fairway. At a drilling density of three wells per section, the potential drilling inventory is 282 gross (161 net) Cardium horizontal locations. The Company continues to explore opportunities to increase its land position in the play through acquisitions and farm-ins in its existing areas of focus and to improve operating efficiencies in the drilling and completion of wells.

The Company also has a significant inventory of Edmonton Sands shallow gas drilling locations as well as some deeper liquids-rich gas locations in central Alberta. Drilling on these prospects can be accelerated in a healthier gas price environment.

The equity financing completed during the first quarter of 2010, along with the Company's expanded available bank lines, provide the Company with the financial flexibility needed to pursue the diversification into oil provided by the development of its Cardium oil lands.

The Company's annual production guidance for 2010 was 7,700 to 8,200 BOED. Due to delays caused by significantly wetter than normal weather in the third quarter of the year, the Company now expects that average production will be at the lower end of this guidance. While the delays resulted in production coming on later than expected, the program was successful and management is pleased with the initial performance from the wells. The Company still estimates to exit the year at approximately 8,700 to 9,000 BOED. Risks associated with this guidance 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. Earnings were negatively impacted in the fourth quarter of 2008 by a $35.4 million charge for impairment of goodwill. Prices have declined from the fourth quarter of 2008 and remain volatile, affecting funds from operations and earnings throughout 2009 and into the third quarter of 2010.



SELECTED QUARTERLY INFORMATION
FOR THE LAST EIGHT FISCAL QUARTERS
($ amounts in thousands, except per share amounts and prices)

Q3 2010 Q2 2010 Q1 2010 Q4 2009
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Oil and gas revenue before royalties $18,928 $ 20,318 $ 23,265 $ 20,439
Funds from operations $ 8,026 $ 9,004 $ 10,635 $ 9,151
Funds from operations per share
Basic $ 0.05 $ 0.05 $ 0.06 $ 0.06
Diluted $ 0.05 $ 0.05 $ 0.06 $ 0.06
Net loss $(9,046) $ (8,891) $ (5,953) $ (6,457)
Net loss per share
Basic $ (0.05) $ (0.05) $ (0.04) $ (0.04)
Diluted $ (0.05) $ (0.05) $ (0.04) $ (0.04)
Capital expenditures, including
acquisitions, net of dispositions $39,528 $ 12,745 $ 33,427 $ 11,312
Cash from operating activities $ 8,437 $ 8,892 $ 12,946 $ 5,361
Daily sales
Natural gas (Mcfd) 35,778 38,998 35,221 34,938
Liquids (bpd) 1,329 1,232 1,130 1,257
BOE (BOED) 7,292 7,732 7,000 7,080
Average prices
Natural gas ($/Mcf) $ 3.43 $ 3.78 $ 5.22 $ 4.28
Liquids ($/bbl) $ 58.61 $ 60.28 $ 62.43 $ 53.79
BOE ($/BOE)(1) $ 28.21 $ 28.88 $ 36.93 $ 31.38
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Q3 2009 Q2 2009 Q1 2009 Q4 2008
----------------------------------------
Oil and gas revenue before royalties $14,617 $ 17,508 $ 24,429 $ 30,102
Funds from operations $ 6,623 $ 6,692 $ 8,792 $ 13,204
Funds from operations per share
Basic $ 0.04 $ 0.06 $ 0.10 $ 0.15
Diluted $ 0.04 $ 0.06 $ 0.10 $ 0.15
Loss before goodwill impairment $(9,432) $(10,410) $(10,159) $ (5,865)
Loss before goodwill impairment per
share
Basic $ (0.06) $ (0.09) $ (0.12) $ (0.07)
Diluted $ (0.06) $ (0.09) $ (0.12) $ (0.07)
Net loss $(9,432) $(10,410) $(10,159) $(41,229)
Net loss per share
Basic $ (0.06) $ (0.09) $ (0.12) $ (0.47)
Diluted $ (0.06) $ (0.09) $ (0.12) $ (0.47)
Capital expenditures, including
acquisitions net of dispositions $ 6,571 $ 2,130 $ 13,545 $ 27,470
Cash from operating activities $ 6,689 $ 2,472 $ 9,298 $ 11,261
Daily sales
Natural gas (Mcfd) 36,282 40,495 42,344 38,090
Liquids (bpd) 1,013 1,040 1,448 1,341
BOE (BOED) 7,060 7,789 8,505 7,689
Average prices
Natural gas ($/Mcf) $ 2.81 $ 3.43 $ 5.15 $ 6.76
Liquids ($/bbl) $ 53.84 $ 49.00 $ 38.69 $ 48.49
BOE ($/BOE)(1) $ 22.50 $ 24.70 $ 31.91 $ 42.55
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(1) Includes royalty and other income classified with oil and gas sales


ADVISORY

Certain information regarding Anderson Energy Ltd. 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, dates of commencement of production, amount of capital expenditures and timing 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 to the royalty regime applicable to the Company, including payment of drilling incentive credits, commodity price outlook and general economic outlook may constitute forward-looking statements under applicable securities laws 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, capital expenditure costs, including drilling, completion and facilities costs, unexpected decline rates in wells, wells not performing as expected, incorrect assessment of the value of acquisitions and farm-ins, failure to realize the anticipated benefits of acquisitions and farm-ins, delays resulting from or inability to obtain required regulatory approvals, changes to government regulation and ability to access sufficient capital from internal and external sources. As a consequence, actual results may differ materially from those anticipated in the 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 Energy's operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) and at Anderson Energy's website (www.andersonenergy.ca).

Furthermore, the forward-looking statements contained in this news release are made as at the date of this news release and Anderson Energy 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.

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 Balance Sheets
(Stated in thousands of dollars)
(Unaudited)

September 30, December 31,
2010 2009


ASSETS
Current assets:
Cash $ - $ 1
Accounts receivable and
accruals (note 7) 20,129 22,990
Prepaid expenses and deposits 3,515 3,778
---------------------------------
23,644 26,769
Property, plant and equipment (note 1) 501,732 470,400
---------------------------------
$ 525,376 $ 497,169
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accruals $ 58,080 $ 36,889

Bank loans (note 2) 67,762 62,404
Asset retirement obligations (note 3) 35,469 33,879
Future income taxes 23,263 31,278
---------------------------------
184,574 164,450

Shareholders' equity:
Share capital (note 4) 421,936 391,637
Contributed surplus (note 4) 7,778 6,104
Deficit (88,912) (65,022)
---------------------------------
340,802 332,719

Commitments (note 8)
Subsequent events (notes 2, 7 and 8)
---------------------------------
$ 525,376 $ 497,169
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----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


ANDERSON ENERGY LTD.
Consolidated Statements of Operations, Comprehensive Loss and Deficit
(Stated in thousands of dollars, except per share amounts)
(Unaudited)

Three months ended Nine months ended
September 30, September 30,
2010 2009 2010 2009
REVENUES
Oil and gas sales $ 18,928 $ 14,617 $ 62,511 $ 56,554
Royalties (1,665) (804) (6,755) (6,522)
Interest income 8 18 72 146
-----------------------------------------
17,271 13,831 55,828 50,178

EXPENSES
Operating 6,515 5,013 20,349 20,075
General and administrative 1,894 1,415 5,560 5,083
Stock-based compensation 483 339 941 852
Interest and other financing
charges 836 780 2,254 2,913
Depletion, depreciation
and accretion 19,582 19,436 58,375 63,176
-----------------------------------------
29,310 26,983 87,479 92,099
-----------------------------------------

Loss before taxes (12,039) (13,152) (31,651) (41,921)
Future income tax reduction (2,993) (3,720) (7,761) (11,920)
-----------------------------------------
Net loss and comprehensive loss
for the period (9,046) (9,432) (23,890) (30,001)
Deficit, beginning of period (79,866) (49,133) (65,022) (28,564)
-----------------------------------------
Deficit, end of period $ (88,912) $(58,565) $(88,912) $(58,565)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net loss per share (note 4)
Basic $ (0.05) $ (0.06) $ (0.14) $ (0.26)
Diluted $ (0.05) $ (0.06) $ (0.14) $ (0.26)
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----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.



ANDERSON ENERGY LTD.
Consolidated Statements of Cash Flows
(Stated in thousands of dollars)
(Unaudited)

Three months ended Nine months ended
September 30, September 30,
2010 2009 2010 2009

CASH PROVIDED BY (USED IN)
OPERATIONS
Net loss for the period $ (9,046) $ (9,432) $(23,890) $(30,001)
Items not involving cash:
Depletion, depreciation and
accretion 19,582 19,436 58,375 63,176
Future income tax reduction (2,993) (3,720) (7,761) (11,920)
Stock-based compensation 483 339 941 852
Asset retirement expenditures (412) - (1,431) (938)
Changes in non-cash working capital:
Accounts receivable and accruals 172 1,149 289 5,859
Prepaid expenses and deposits (28) (83) 964 (1,337)
Accounts payable and accruals 679 (1,000) 2,788 (7,232)
-----------------------------------------
8,437 6,689 30,275 18,459

FINANCING
Increase (decrease) in bank loans 12,154 (5,830) 5,358 (22,640)
Issue of common shares, net
of issue costs - - 29,792 56,538
Changes in non-cash working capital:
Accounts payable and accruals (47) (159) 103 161
-----------------------------------------
12,107 (5,989) 35,253 34,059

INVESTMENTS
Additions to property, plant
and equipment (39,720) (6,571) (87,893) (22,300)
Proceeds on disposition of
properties 192 - 2,193 54
Changes in non-cash working capital:
Accounts receivable and accruals (1,591) 1,435 2,572 11,645
Prepaid expenses and deposits (542) 13 (701) (53)
Accounts payable and accruals 21,114 (3,715) 18,300 (41,865)
-----------------------------------------
(20,547) (8,838) (65,529) (52,519)
-----------------------------------------
Decrease in cash (3) (8,138) (1) (1)
Cash and cash equivalents,
beginning of period 3 8,138 1 1
-----------------------------------------
Cash and cash equivalents,
end of period $ - $ - $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See note 6 for additional cash information.

See accompanying notes to the consolidated financial statements.


ANDERSON ENERGY LTD.
Notes to the Consolidated Financial Statements

THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2010 AND 2009

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


Anderson Energy Ltd. ("Anderson Energy" or the "Company") was incorporated under the laws of the province of Alberta on January 30, 2002. Anderson Energy is engaged in the acquisition, exploration and development of oil and gas properties in western Canada. These interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the consolidated financial statements for the year ended December 31, 2009. The disclosures included below are incremental to those included with the annual consolidated financial statements. These interim consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto for the year ended December 31, 2009.



1. PROPERTY, PLANT AND EQUIPMENT

September 30, December 31,
2010 2009

Cost $ 811,367 $ 723,549
Less accumulated depletion and depreciation (309,635) (253,149)
------------------------------
Net book value $ 501,732 $ 470,400
----------------------------------------------------------------------------
----------------------------------------------------------------------------


At September 30, 2010, unproved property costs of $5.4 million (December 31, 2009 - $6.2 million) have been excluded from the full cost pool for depletion and depreciation calculations. Future development costs of proved, undeveloped reserves of $158.5 million (December 31, 2009 - $197.6 million) have been included in the depletion and depreciation calculation.

For the nine months ended September 30, 2010, $3.7 million (September 30, 2009 - $3.5 million) of general and administrative costs including $0.7 million (September 30, 2009 - $0.8 million) of stock-based compensation costs were capitalized. The future tax liability of $0.3 million (September 30, 2009 - $0.3 million) associated with the capitalized stock-based compensation has also been capitalized. For the three months ended September 30, 2010, $1.5 million (September 30, 2009 - $1.1 million) of general and administrative costs including $0.3 million (September 30, 2009 - $0.3 million) of stock-based compensation costs were capitalized. Capitalized general and administrative costs consist of salaries and associated office rent of staff involved in capital activities.

No impairment was recognized under the ceiling test at September 30, 2010. The future commodity prices used in the ceiling test were based on commodity price forecasts of the Company's independent reserve engineers adjusted for differentials specific to the Company's reserves. Factors used in the ceiling test calculation are as follows:



AECO
Gas Price WTI Cushing Exchange rate
($Cdn/Mcf) ($US/bbl) (US$/Cdn)
2010 Q4 4.00 80.00 0.95
2011 4.37 83.00 0.95
2012 5.05 86.00 0.95
2013 5.74 89.00 0.95
2014 6.32 92.00 0.95
2015 6.79 93.84 0.95
2016 7.16 95.72 0.95
2017 7.47 97.64 0.95
2018 7.63 99.59 0.95
2019 7.81 101.58 0.95
Thereafter 2%
----------------------------------------------------------------------------


After 2019, only inflationary growth of 2% was considered. Natural gas liquids prices were tied to crude oil prices based on historical trends and analysis. Exchange rates were expected to remain consistent from 2019 forward.

2. BANK LOANS

At September 30, 2010, total bank facilities were $115 million consisting of an $80 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 working capital credit facility have a revolving period ending on July 12, 2011, extendible at the option of the lenders. If not extended, these facilities cease to revolve and all outstanding advances thereunder become repayable one year from the term date of July 12, 2011. The supplemental facility is also available on a revolving basis and is scheduled to expire on July 1, 2011, with any outstanding amounts due in full at that time. No amounts were drawn under the supplemental facility at September 30, 2010.

The average effective interest rate on advances under the facilities in 2010 was 4.9% (September 30, 2009 - 4.2%). The Company has $133,500 in letters of credit outstanding at September 30, 2010, which reduces the amount of credit available to the Company.

In November 2010, the Company entered into an agreement with its syndicate of banks to increase the total facilities to $125 million. The supplemental facility was increased to $35 million, subject to completion of customary loan documentation. Draws over $30 million under the supplemental facility will be subject to the consent of the syndicate at the time of the drawdown.

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. The margins vary depending on the borrowing option used and the Company's financial ratios. At September 30, 2010, there were no advances in U.S. funds.

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

The available lending limits of the facilities are reviewed semi-annually with the next review set for May 2011, and are based on the bank syndicate's interpretations of the Company's reserves and future commodity prices. There can be no assurance that the amount of the available facilities or the applicable margins will not be adjusted during the lender's review.

3. ASSET RETIREMENT OBLIGATIONS

The Company estimates the total undiscounted cash flows required to settle its asset retirement obligations is approximately $72.2 million (December 31, 2009 - $70.1 million), including expected inflation of 2% (December 31, 2009 - 2%) per annum. The majority of the costs will be incurred between 2010 and 2020. A credit adjusted risk-free rate of 8% to 10% (December 31, 2009 - 8% to 10%) was used to calculate the fair value of the asset retirement obligations. A reconciliation of the asset retirement obligations is provided below:



September 30, December 31,
2010 2009

Balance, beginning of period $ 33,879 $ 30,820
Liabilities incurred 594 1,544
Liabilities settled (1,431) (1,482)
Change in estimate 538 666
Accretion expense 1,889 2,331
------------------------------
Balance, end of period $ 35,469 $ 33,879
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----------------------------------------------------------------------------


4. SHARE CAPITAL AND CONTRIBUTED SURPLUS

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 December 31, 2008 87,300,401 $ 334,176
Issued pursuant to prospectus (1) 63,200,000 60,040
Share issue costs - (3,502)
Tax effect of share issue costs - 923
------------------------------
Balance at December 31, 2009 150,500,401 $ 391,637
Issued pursuant to prospectus (2) 21,900,000 31,755
Share issue costs - (1,963)
Tax effect of share issue costs - 507
------------------------------
Balance at September 30, 2010 172,400,401 $ 421,936
----------------------------------------------------------------------------
(1) Includes 4,992,034 common shares issued to management and directors and
3,377,966 common shares issued to family of management and directors
for total gross proceeds of $8.0 million.
(2) Includes 352,466 common shares issued to directors for total gross
proceeds of $0.5 million.


Stock options. The Company has an employee stock option plan under which employees, directors and consultants are eligible to receive grants. The exercise price of stock options equals the weighted average trading price of the Company's 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, 2010 and year ended December 31, 2009 are as follows:



Weighted
Number of average
options exercise price

Balance at December 31, 2008 7,594,856 $ 4.37
Granted 3,316,200 0.80
Expirations (252,300) 6.47
Forfeitures (400,000) 3.01
------------------------------
Balance at December 31, 2009 10,258,756 $ 3.22
Granted 3,950,250 1.06
Expirations (587,900) 6.10
Forfeitures (446,750) 1.61
------------------------------
Balance at September 30, 2010 13,174,356 $ 2.50
----------------------------------------------------------------------------

Exercisable at September 30, 2010 7,003,823 $ 3.75
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Options outstanding Options exercisable

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

$0.79 to $0.99 2,828,200 $ 0.79 3.8 987,200 $ 0.79
$1.00 to $1.50 4,030,350 1.06 4.8 17,700 1.05
$2.26 to $3.35 774,450 2.68 2.8 518,800 2.68
$3.36 to $5.00 4,778,156 4.00 1.6 4,719,923 4.00
$5.01 to $7.50 333,600 5.75 0.7 330,600 5.75
$7.51 to $8.06 429,600 7.61 0.2 429,600 7.61
----------------------------------------------------------
Total at
September 30,
2010 13,174,356 $ 2.50 3.1 7,003,823 $ 3.75
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The fair value of the options issued during the nine months ended September 30, 2010 was $0.55 (September 30, 2009 - $0.42) per option. The weighted average assumptions used in arriving at the values were: a risk-free interest rate of 2.3% (September 30, 2009 - 2.4%), expected option life of five years (September 30, 2009 - five years), expected volatility of 58% (September 30, 2009 - 60%) and a dividend yield of 0% (September 30, 2009 - 0%).

Per share amounts. During the nine months ended September 30, 2010 there were 169,568,716 weighted average shares outstanding (September 30, 2009 - 116,469,632). On a diluted basis, there were 169,568,716 weighted average shares outstanding (September 30, 2009 - 116,469,632) after giving effect to dilutive stock options. During the three months ended September 30, 2010 there were 172,400,401 weighted average shares outstanding (September 30, 2009 - 150,500,401). On a diluted basis, there were 172,400,401 weighted average shares outstanding (September 30, 2009 - 150,500,401) after giving effect to dilutive stock options. At September 30, 2010, there were 13,174,356 options that were anti-dilutive (September 30, 2009 - 10,526,656).



Contributed surplus

Amount
Balance at December 31, 2008 $ 4,000
Stock-based compensation 2,104
-----------
Balance at December 31, 2009 $ 6,104
Stock-based compensation 1,674
-----------
Balance at September 30, 2010 $ 7,778
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Employee stock savings plan. Effective July 1, 2008, the Company initiated an Employee Stock Savings Plan ("ESSP"). Employees could contribute up to 5% of their base salaries towards the purchase of Company shares and the Company matched these contributions. The ESSP was suspended between April 1, 2009 and March 31, 2010 due to market conditions. The Company reinstated the plan effective April 1, 2010. The Company's matching contribution for the nine months ended September 30, 2010 was $127,000 (September 30, 2009 - $77,000) and is included in general and administrative expenses.

5. MANAGEMENT OF CAPITAL STRUCTURE

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 $340.8 million, long-term bank loans of $67.8 million and the working capital deficiency of $34.4 million. 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 Energy 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 working capital deficiency and outstanding long-term bank loans) by the annualized current quarter funds from operations (cash flow from operating activities before changes in non-cash working capital and asset retirement 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,
2010 2009

Bank loans $ 67,762 $ 62,404
Current liabilities 58,080 36,889
Current assets (23,644) (26,769)
----------------------------------------------------------------------------
Total debt $ 102,198 $ 72,524

Cash from operating activities in quarter $ 8,437 $ 5,361
Changes in non-cash working capital (823) 3,246
Asset retirement expenditures 412 544
----------------------------------------------------------------------------
Funds from operations in quarter $ 8,026 $ 9,151
Annualized current quarter funds
from operations $ 32,104 $ 36,604

Total debt to funds from operations 3.2 2.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------


At September 30, 2010, the Company's total debt to annualized funds from operations was 3.2. At December 31, 2009, the Company's total debt to annualized funds from operations was 2.0. The increase in the debt to funds from operations ratio in the third quarter of 2010 is due to $39.5 million in net capital expenditures and lower natural gas prices in the quarter. New production resulting from the capital expenditures is not yet reflected in the reported funds from operations. As this new crude oil production is brought on stream at higher expected operating margins, the debt to funds from operations ratio is expected to decrease.

The Company's share capital is not subject to external restrictions, however, its credit facilities are petroleum and natural gas reserves based (see note 2). Anderson Energy has not paid or declared any dividends since the date of incorporation and does not contemplate doing so in the foreseeable future.



6. CASH PAYMENTS

The following cash payments were made (received):

September 30, December 31,
2010 2009

Interest paid $ 1,549 $ 2,198
Interest received (67) (147)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


7. FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT

The Company's financial instruments include cash, accounts receivable and accruals, accounts payable and accruals and bank loans. The fair value of cash approximates its carrying value due to its short-term nature. The fair value of accounts receivable and accruals and accounts payable and accruals approximate their carrying value due to their demand nature or relatively short periods to maturity. The fair value of bank loans approximates their carrying value as they bear interest at a floating rate.

The Company has exposure to credit risk, liquidity risk and market risk as a result of its use of financial instruments.

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. As at September 30, 2010, the maximum credit exposure is the carrying amount of the accounts receivable and accruals of $20.1 million (December 31, 2009 - $23.0 million). As at September 30, 2010, the Company's receivables consisted of $12.8 million (December 31, 2009 - $14.4 million) from joint venture partners and other trade receivables and $7.3 million (December 31, 2009 - $8.6 million) of revenue accruals and other receivables from petroleum and natural gas marketers. Of the $7.3 million of revenue accruals and receivables from petroleum and natural gas marketers, $6.7 million was received on or about October 25, 2010. The balance is expected to be received in subsequent months through joint venture billings from partners.

The Company's allowance for doubtful accounts as at September 30, 2010 is $1.6 million (December 31, 2009 - $1.6 million). The Company did not write-off any receivables during the nine months ended September 30, 2010.

As at September 30, 2010 the Company considers it receivables, net of allowance for doubtful accounts, to be aged as follows:



Aging September 30, 2010
Not past due $ 19,438
Past due by less than 120 days 390
Past due by more than 120 days 301
--------------------
Total $ 20,129
----------------------------------------------------------------------------
----------------------------------------------------------------------------


These amounts are before offsetting amounts owing to joint venture partners that are included in accounts payable and accrued liabilities.

Liquidity risk. Liquidity risk is the risk that the Company will incur difficulties meeting its financial obligations as they are due.

The following are the contractual maturities of financial liabilities and associated interest payments as at September 30, 2010:



Financial Liabilities less than 1 Year 1-2 Years
Accounts payable and accruals $ 58,080 $ -
Bank loans - principal - 67,762
-------------------------------
Total $ 58,080 $ 67,762
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Please refer to note 2 for additional details on bank loans and to note 8 for additional details on commitments.

Market risk. Market risk consists of currency risk, commodity price risk and interest rate risk.

Currency risk. Foreign currency exchange rate risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in foreign exchange rates. The Company had no outstanding forward exchange rate contracts in place at September 30, 2010 or December 31, 2009.

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. In December 2009, the Company entered into physical sales contracts to sell 20,000 GJ per day of natural gas for each of January, February and March 2010 at an average AECO price of $5.41 per GJ. The gains realized were $1.3 million and have been included in oil and gas sales. There were no commodity price risk contracts outstanding at September 30, 2010. In October 2010, the Company entered into fixed price swaps for 1,000 barrels per day of crude oil for December 2010 at a NYMEX crude oil price of Canadian $85.70 per barrel and for calendar 2011 at a NYMEX crude oil price of Canadian $88.45 per barrel.

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 Company is exposed to interest rate fluctuations on its bank debt which bears interest at a floating rate. For the nine months ended September 30, 2010, if interest rates had been 1% lower with all other variables held constant, earnings for the period would have been $0.2 million (September 30, 2009 - $0.4 million) higher, due to lower interest expense. An equal and opposite impact would have occurred had interest rates been higher by the same amounts. The decrease period over period is due to lower average debt levels outstanding. The Company had no interest rate swap or financial contracts in place at September 30, 2010 or December 31, 2009.

8. COMMITMENTS

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 December 31, 2010. Subsequent to September 30, 2010, the terms of the farm-in agreement were modified to extend the commitment date to March 31, 2012. 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 31, 2013 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 September 30, 2010, the Company has drilled 126 wells under the farm-in agreement and plans to defer the drilling of the remaining 74 wells past 2010. 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, 2012, 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.

The Company has entered into an agreement to lease office space until November 30, 2012. Future minimum lease payments are expected to be $0.4 million for the remainder of 2010, $1.8 million in 2011 and $1.6 million in 2012.

The Company entered into firm service transportation agreements for approximately 31 million cubic feet per day of gas sales in central Alberta for various terms expiring in one to ten years. Based on rate schedules announced to date, the payments in each of the next five years and thereafter are estimated as follows:



Committed volume Committed
(MMcfd) amount

2010 Q4 30 $ 579
2011 31 $ 2,198
2012 20 $ 1,569
2013 8 $ 894
2014 4 $ 700
Thereafter 12 $ 1,013
----------------------------------------------------------------------------



Corporate Information Contact Information

Head Office Anderson Energy Ltd.
700 Selkirk House Brian H. Dau
555 4th Avenue S.W. President & Chief Executive Officer
Calgary, Alberta (403) 262-6307
Canada T2P 3E7
Phone (403) 262-6307
Fax (403) 261-2792
Website www.andersonenergy.ca

Directors Officers

J.C. Anderson J.C. Anderson
Calgary, Alberta Chairman of the Board

Brian H. Dau (3) Brian H. Dau
Calgary, Alberta President & Chief Executive Officer

Chris L. Fong (1) (2) David M. Spyker
Calgary, Alberta Chief Operating Officer

Glenn D. Hockley (1) (3) M. Darlene Wong
Calgary, Alberta Vice President Finance, Chief Financial
Officer & Secretary

David J. Sandmeyer (2) (3) Blaine M. Chicoine
Calgary, Alberta Vice President, Operations

David G. Scobie (1) (2) Sandra M. Drinnan
Calgary, Alberta Vice President, Land

Member of: Philip A. Harvey
(1) Audit Committee Vice President, Exploitation
(2) Compensation & Corporate
Governance Committee Jamie A. Marshall
(3) Reserves Committee Vice President, Exploration

Auditors Abbreviations used
KPMG LLP AECO - intra-Alberta Nova inventory
Transfer price
Independent Engineers bbl - barrel
GLJ Petroleum Consultants bpd - barrels per day
Mstb - thousand stock tank barrels
Legal Counsel BOE - barrels of oil equivalent
Bennett Jones LLP BOED - barrels of oil equivalent per day
MBOE - thousand barrels of oil equivalent
Registrar & Transfer Agent GJ - gigajoule
Valiant Trust Company Mcf - thousand cubic feet
Mcfd - thousand cubic feet per day
Stock Exchange MMcf - million cubic feet
The Toronto Stock Exchange MMcfd - million cubic feet per day
Symbol AXL NGL - natural gas liquids



Contact Information