Anderson Energy Ltd.
TSX : AXL

Anderson Energy Ltd.

November 12, 2008 09:00 ET

Anderson Energy Ltd. Announces 2008 Third Quarter Results

CALGARY, ALBERTA--(Marketwire - Nov. 12, 2008) - Anderson Energy Ltd. ("Anderson Energy" or the "Company") (TSX:AXL) is pleased to announce its operating and financial results for the third quarter ended September 30, 2008.

Highlights

- Funds from operations for the third quarter more than tripled to $21.2 million ($0.24 per share) compared to the third quarter of 2007. Funds from operations for the nine months ended September 30, 2008 were $66.1 million ($0.76 per share) as compared to $23.9 million ($0.39 per share) for the same nine months in 2007 and $36.4 million ($0.54 per share) for the full year ended December 31, 2007.

- Third quarter production averaged 7,671 BOED, 44% higher than the third quarter of 2007.

- The Company realized an average natural gas price of $7.86 per Mcf in the third quarter of 2008 as compared to $5.00 per Mcf in the third quarter of 2007.

- Operating expenses averaged $10.10 per BOE in the third quarter, which is 15% lower than the third quarter of 2007 and 11% lower than the second quarter of 2008. The reduction in operating expenses is primarily due to new gas plant projects that came on stream during the quarter.

- Operating netbacks improved to $34.34 per BOE for the third quarter compared to $16.76 per BOE in the third quarter of 2007.

- The Company's future drilling inventory is 1,144 gross (585 net) wells as of September 30, 2008, based on a four well per section Edmonton Sands drilling density.

- The Company has entered into letters of intent to sell six properties for a total of $18 million. The property sales are projected to reduce 2009 production by approximately 330 BOED. Closing of the transactions is subject to completion of definitive purchase and sale agreements and other normal closing conditions.

- Subsequent to the third quarter, the Company brought on production four Mannville oil and gas wells that were drilled in the third quarter in central Alberta with current production of 800 BOED. The Company made new exploration discoveries with a gas discovery in Bigoray and a light oil discovery in Willesden Green.

- The Edmonton Sands winter drilling program has commenced, with 123 wells planned for this winter, approximately 90 in the fourth quarter of 2008 and 33 in the first quarter of 2009.



Financial and Operating Highlights
Three months ended % Nine months ended %
September 30 Change September 30 Change
------------------------------------------------------------
2008 2007 2008 2007
------------------------------------------------------------
Financial
(thousands of
dollars,
except share
data)

Total oil and
gas revenue $39,427 $ 17,261 128% $126,143 $ 55,810 126%

Funds from
operations $21,212 $ 6,255 239% $ 66,124 $ 23,850 177%
Per common
share - basic $ 0.24 $ 0.09 167% $ 0.76 $ 0.39 95%
- diluted $ 0.24 $ 0.09 167% $ 0.76 $ 0.39 95%

Earnings (loss) $ 4,160 $ (3,018) 238% $ 14,365 $ (2,683) 635%
Per common
share - basic $ 0.05 $ (0.04) 225% $ 0.16 $ (0.04) 500%
- diluted $ 0.05 $ (0.04) 225% $ 0.16 $ (0.04) 500%

Field capital
expenditures 27,050 17,924 51% 80,056 54,389 47%
Acquisitions, net of
dispositions 18 118,042 (100%) (857) 126,444 (101%)

Debt, net of working
capital 110,535 79,046 40%

Shareholders' equity $350,110 $329,179 6%

Average shares
outstanding
(thousands)
Basic 87,300 70,254 24% 87,297 61,222 43%
Diluted 87,300 70,254 24% 87,400 61,222 43%

Ending shares
outstanding
(thousands) 87,300 87,294 0%

Operating (6Mcf:1bbl
conversion)

Average daily
sales
Natural gas (Mcfd) 38,703 26,860 44% 39,263 24,000 64%
Light/medium
crude oil (bpd) 434 485 (11%) 486 520 (7%)
NGL (bpd) 787 358 120% 791 213 271%
Barrels of oil
equivalent
(BOED) 7,671 5,320 44% 7,820 4,732 65%

Average sales
price
Natural gas
($/Mcf) 7.86 5.00 57% 8.57 6.67 28%
Light/medium
crude oil
($/bbl) 112.18 66.03 70% 104.70 59.03 77%
NGL ($/bbl) 78.06 59.62 31% 81.67 56.44 45%
Barrels of oil
equivalent
($/BOE) 55.87 35.27 58% 58.87 43.20 36%

Royalties ($/BOE) 11.43 6.68 71% 12.76 8.21 55%
Operating
costs ($/BOE) 10.10 11.83 (15%) 11.19 11.69 (4%)
Operating
netbacks ($/BOE) 34.34 16.76 105% 34.92 23.30 50%
General and
administrative
($/BOE) 2.90 3.23 (10%) 2.51 3.82 (34%)

Wells drilled
(gross) 39 34 15% 126 82 54%


Operating Highlights

Production:

In the third quarter of 2008, production averaged 7,671 BOED, an increase of 44% over the third quarter of 2007 and 3% less than the second quarter of 2008. The Company experienced plant outages at various facilities and third party production curtailments in the month of September. As well, the Company was delayed on various well tie-in projects during the quarter. As of November 11, 2008, the Company's behind pipe production capability is approximately 1,200 BOED. Approximately 90% of the behind pipe production capability relates to wells drilled prior to September 30, 2008 and not yet on stream. The remainder relates to the current fourth quarter drilling program. In addition, the Company has 300 BOED of production curtailed by third parties in its Westpem property. This production may be shut-in until the new Westpem pipeline project comes on stream, which is estimated to be in December. The Company now expects production to average approximately 7,800 BOED for fiscal 2008, which is 5% less than previously estimated due to the delay in well tie-ins and the Westpem third party production curtailment.

Financial:

The Company's funds from operations in the third quarter were $21.2 million and earnings were $4.2 million. This compares to funds from operations of $6.3 million and a loss of $3.0 million in the third quarter of 2007 and funds from operations of $27.3 million and $8.5 million in earnings during the second quarter of 2008. Natural gas prices were $7.86 per Mcf in the third quarter of 2008, compared to $5.00 per Mcf in the third quarter of 2007 and $10.26 per Mcf in the second quarter of 2008. Since the end of the quarter, natural gas prices have pulled back with October AECO spot prices being approximately $6.75 per Mcf as compared to an average of $7.34 per Mcf in the third quarter. Crude oil and natural gas liquids prices in the third quarter were $90.19 per bbl as compared to $63.31 per bbl in the third quarter of 2007. Current WTI oil prices are 50% lower than WTI oil prices experienced in the third quarter, however the Canadian dollar has also weakened relative to the U.S. dollar from 96 cents to 83 cents, which mitigates some of the oil price drop. The Company's operating netback was $34.34 per BOE in the third quarter of 2008 compared to $16.76 per BOE in the third quarter of 2007. The Company's operating expenses in the third quarter were $10.10 per BOE as compared to $11.83 per BOE in the third quarter of 2007 and $11.32 per BOE in the second quarter of 2008. This reduction in operating expenses is due to the new gas plant projects that came on stream early in the third quarter, the sale of a property with high operating expenses in the second quarter and reduced workovers in the current quarter.

Capital Program:

Capital expenditures were $27.1 million during the quarter, of which $17.8 million was spent on drilling and completions and $7.7 million on facilities.

In the third quarter, the Company drilled 39 gross (25.2 net) wells at a 92% success rate. Twenty gross (13.8 net) Edmonton Sands wells were drilled at a 95% success rate. In the deep drilling program, the Company drilled 11 gross (9.4 net) wells resulting in six deep gas wells, two oil wells, two dry holes and one potential gas well awaiting uphole completion. All of the deep gas and oil discoveries are slated to be tied in during the fourth quarter. The Company also participated in seven gross (1.3 net) outside operated CBM wells in the quarter.

As part of the deep program, the Company drilled three gross Rock Creek wells that initially tested at 2,400 Mcfd, 2,000 Mcfd and 1,200 Mcfd. A third party gas processing company is having a pipeline constructed into the Westpem area which is expected to be on stream in December. These three new wells, plus the Company's existing Westpem wells, some of which are currently shut-in, will be tied in to this pipeline when it is completed. The remainder of the Company's deep program is in the Willesden Green and Bigoray areas and the four wells that have been tied in to date are producing approximately 800 BOED. Although the wells drilled targeted infill development opportunities, we did encounter a new gas pool in Bigoray with a stabilized AOF of 13 MMcfd and a new light oil pool discovery in Willesden Green. The Willesden Green oil discovery is projected to be on stream at the end of this month.

The Company's Chedderville test is still ongoing and is expected to be completed this quarter.

The Company has commenced its Edmonton Sands winter drilling program and as of November 11, 2008, the Company has drilled 11 gross (6.3 net) wells.

Dispositions:

In the fourth quarter of 2008, the Company entered into letters of intent to sell four properties in Alberta and two in British Columbia for total proceeds of $18 million before adjustments. The property sales are projected to reduce 2009 production by approximately 330 BOED. The property sales are subject to the execution of definitive purchase and sale agreements and normal closing conditions and are expected to close in late 2008 or early 2009.

Outlook:

We have seen significant, unprecedented changes in capital, equity, commodity and currency markets in the past few months and ongoing concerns about the global credit crunch. The Company feels it is prudent to continue its fourth quarter Edmonton Sands capital program where possible to increase its exit production. To help finance the fourth quarter capital program, the Company is in the process of selling non-core, principally non-operated assets. However, commodity prices are weaker than originally forecasted and extremely volatile. The Company's original plan was to drill 200 gross (130 net) Edmonton Sands wells in the fourth quarter of 2008 and the first quarter of 2009. At this time, it appears the Company will drill approximately 123 gross (85 net) Edmonton Sands wells with most of the program deletions in the first quarter of 2009. Approximately 70% of the planned drilling for the winter program will be in the fourth quarter of 2008. The Company will evaluate the strength and direction of commodity prices at year end to determine if an upward or downward adjustment is warranted in the winter drilling program.

The Company feels it is most advantageous from an access, on stream timeliness and cost perspective to drill wells in the winter months, and to try to tie-in all wells drilled prior to spring breakup. This winter program is designed to do just that and avoid the problems that occur during wet summer months.

With the delay in well tie-ins, property dispositions and the Westpem third party production curtailment, the Company expects to produce approximately 7,800 BOED in 2008. The Company estimates that it will be producing more than 9,000 BOED by the end of the year.

The Company will be reviewing its 2009 capital and operating budgets and associated guidance in January 2009.

As of September 30, 2008, the Company has identified 1,144 gross (585 net) drilling locations, of which 88% are net Edmonton Sands locations and 7% are net Horseshoe Canyon Coal Bed Methane locations. Most of the drilling inventory consists of development locations.

The Company's Edmonton Sands drilling inventory is calculated based on four wells per section. When the Company elects to down space to six and eight wells per section, there would be a substantial increase in its drilling inventory.

Most of the Company's drilling inventory is low cost, lower productivity natural gas which at current prices attracts similar royalties under both the existing and proposed Alberta government royalty regimes. Therefore, the introduction of the new Alberta royalty framework in 2009 is not expected to have a significant impact on either the pace of the Company's activity or the intrinsic value of the drilling inventory.

The Company has grown its Edmonton Sands land position on a net section basis from 303 gross (179 net) sections at December 31, 2007 to 328 gross (198 net) sections as of November 1, 2008.

The Company is continuing to pursue Edmonton Sands farm-in opportunities and acquisition opportunities within its core area.

We encourage anyone interested in further details on our Company to visit our website at www.andersonenergy.ca.

Brian H. Dau, President and Chief Executive Officer

November 11, 2008


Anderson Energy Ltd.

Management's Discussion and Analysis

For the Three and Nine Months Ended September 30, 2008 and 2007:

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, 2008 and 2007 and the audited consolidated financial statements and management's discussion and analysis of Anderson Energy for the years ended December 31, 2007 and 2006 and is based on information available as of November 11, 2008.

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 and barrels of oil equivalent. 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 reserve additions and are an indicator of the efficiency of capital expended in the period. Production volumes and reserves are commonly expressed on a barrel of oil equivalent ("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:

Sales volumes for the three months ended September 30, 2008 averaged 7,671 BOED, 44% higher than the same period in 2007 but slightly lower than the previous quarter due to plant outages and tie-in delays. The Company reported significantly improved operating expenses on a per barrel basis in the quarter due to the completion of construction on three gas plant projects. Funds from operations for the three months ended September 30, 2008 were $21.2 million, 3.4 times higher than 2007 but 22% lower than the previous quarter due to significantly lower commodity prices.

Capital expenditures were $27.1 million for the three months ended September 30, 2008. During the third quarter of 2008, the Company drilled 39 gross (25.2 net) wells, of which 36 gross (23.2 net) were successful. The Company spent $17.8 million on drilling and completion projects and $7.7 million on facilities in the quarter.

Debt, net of working capital, was $110.5 million at September 30, 2008, and was in line with expectations. The Company continues to plan to spend $117.0 million on its capital program in 2008, and to manage the impact of lower commodity prices on cash flows by agreeing to sell non-core properties in the fourth quarter of 2008. However, with the current uncertainty and volatility in world markets, the Company has revised its 2008-2009 winter drilling program downward from 200 gross wells to 123 gross wells, with the majority of the program deletions taking place in the first quarter of 2009.

Revenue and Production:

Gas sales comprised 84% of Anderson Energy's total oil and gas sales volumes for the three months ended September 30, 2008, consistent with the second quarter of 2008.

In the third quarter of 2008, gas sales volumes were 44% higher than the previous year. On a year to date basis, gas sales volumes were 64% higher than the previous year. The increases were due to asset acquisitions completed in 2007 and drilling successes. Gas sales volumes were 38.7 Mmcfd in the third quarter of 2008, which was slightly less than expected due to delays in well tie-ins and plant outages at various facilities in the month of September.

Oil sales for the three months ended September 30, 2008 averaged 434 bpd compared to 485 bpd in the third quarter of 2007 and 436 bpd in the second quarter of 2008. Oil sales for the nine months ended September 30, 2008 were 486 bpd, 7% lower than the first nine months of 2007 due largely to the sale of minor oil properties earlier in the year. The majority of the Company's oil production is from central and eastern Alberta.

Natural gas liquids sales for the three months ended September 30, 2008 averaged 787 bpd compared to 358 bpd for the third quarter of 2007 and 829 bpd in the second quarter of 2008. Natural gas liquids sales for the nine months ended September 30, 2008 averaged 791 bpd compared to 213 bpd for the first nine months of 2007. Development activity on the liquids rich assets acquired in the September 2007 acquisition contributed to the volume increases from 2007.

The following tables outline production revenue, volumes and average sales prices for the three and nine months ended September 30, 2008 and 2007.



Three months ended Nine months ended
September 30 September 30
------------------------------------------
Oil and Natural Gas Revenue 2008 2007 2008 2007
(thousands of dollars)
Natural gas $ 28,005 $ 12,361 $ 93,531 $ 42,557
Natural gas hedging gain (loss) - - (1,341) 1,157
Oil 4,478 2,947 13,930 8,376
NGL 5,650 1,963 17,701 3,274
Royalty and other 1,294 (10) 2,322 446
------------------------------------------
Total $ 39,427 $ 17,261 $ 126,143 $ 55,810
------------------------------------------
------------------------------------------

Production
Natural gas (Mcfd) 38,703 26,860 39,263 24,000
Oil (bpd) 434 485 486 520
NGL (bpd) 787 358 791 213
------------------------------------------
Total (BOED) 7,671 5,320 7,820 4,732
------------------------------------------
------------------------------------------

Prices
Natural gas ($/Mcf) $ 7.86 $ 5.00 $ 8.57 $ 6.67
Oil ($/bbl) 112.18 66.03 104.70 59.03
NGL ($/bbl) 78.06 59.62 81.67 56.44
Total ($/BOE)(1) $ 55.87 $ 35.27 $ 58.87 $ 43.20

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


Natural gas prices remain volatile. Anderson Energy's average gas sales price was $7.86 per Mcf for the three months ended September 30, 2008, 23% lower than the second quarter of 2008 price of $10.26 per Mcf and 57% higher than the third quarter of 2007 price of $5.00 per Mcf. Anderson Energy's average gas sales price was $8.57 per Mcf for the nine months ended September 30, 2008. In February and March of 2008, the Company had a fixed price natural gas sales contract for 25,000 GJ per day at $6.89 per GJ. This contract resulted in a $1.3 million loss in sales. The average gas price for the nine months ended September 30, 2008 was $8.69 per Mcf before this loss. Commodity prices have fallen dramatically since early summer in conjunction with the overall global economic crisis.

There were no physical or financial hedging contracts outstanding as at September 30, 2008.

Anderson Energy sells most of its gas at the daily or monthly index less associated transportation. The AECO 5A daily index was $7.34 per GJ for the three months ended September 30, 2008 compared to $9.68 per GJ in the second quarter of 2008 and $4.91 per GJ in the third quarter of 2007. Average gas prices received by the Company reflected market price changes.

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 27.6 MMcfd of natural gas sales for various terms ranging from one to seven years.

Royalties:

Royalties were 20% of revenue for the three months ended September 30, 2008 compared to 19% for the third quarter of 2007 and 22% for the second quarter of 2008. Royalties were 22% of revenue for the nine months ended September 30, 2008 compared to 19% for the same period in 2007. Royalties in 2007 were reduced by credits related to prior period gas cost allowance assessments. In addition, royalty rates increased in the current year as a result of the higher rate gas wells and higher natural gas liquids yields associated with the wells acquired in the September 2007 acquisition and the prolific new wells that came on stream in the first quarter of 2008. Royalty expense on a BOE basis will vary with commodity prices.

On October 25, 2007, the Alberta government announced proposed significant upward revisions to the Crown royalty system. While the proposed changes are expected to have a negative impact on the oil and gas business as a whole, the impact on shallow gas programs is expected to be less than on other areas of the business. Anderson Energy believes that the proposed changes will only have a small impact on royalties at current production levels and prices. The changes do not negatively impact our long-term Edmonton Sands business strategy, as the focus is predominantly on shallow gas lower productivity wells. These changes are expected to come into effect on January 1, 2009 and are discussed further under "Business Risks".



Three months ended Nine months ended
Sept 30 Sept 30
------------------------------------------
2008 2007(1) 2008 2007(1)
------------------------------------------

Royalties (%) 20% 19% 22% 19%
Royalties ($/BOE) $ 11.43 $ 6.68 $ 12.76 $ 8.21

(1) lower than normal due to credits related to prior period gas cost
allowance assessments


Operating Expenses:

Operating expenses were $10.10 per BOE for the three months ended September 30, 2008 compared to $11.83 per BOE in the third quarter of 2007 and $11.32 per BOE in the second quarter of 2008. Operating expenses were $11.19 per BOE for the nine months ended September 30, 2008 compared to $11.69 per BOE in the first nine months of 2007. The reduction in operating expenses in the third quarter of 2008 is due to the new gas plant projects that came on stream early in the quarter and started to reduce the Company's dependence on third party processing, as well as the sale of a property with high operating expenses in the second quarter and reduced workovers in the current quarter. The Company is continuing with the Chedderville Leduc A sour gas pool test in the fourth quarter, which is expected to have higher than average operating costs. The Chedderville test impacted third quarter operating expenses by approximately $0.20/BOE.



Operating Netback:
Three months ended Nine months ended
September 30 September 30
------------------------------------------
2008 2007 2008 2007
(thousands of dollars)

Revenue $ 39,427 $ 17,261 $ 126,143 $ 55,810
Royalties (8,070) (3,270) (27,344) (10,606)
Operating expenses (7,126) (5,788) (23,970) (15,098)
------------------------------------------
$ 24,231 $ 8,203 $ 74,829 $ 30,106
------------------------------------------
------------------------------------------

Sales (MBOE) 705.8 489.4 2,142.8 1,291.9
------------------------------------------
------------------------------------------

Per BOE
Revenue $ 55.87 $ 35.27 $ 58.87 $ 43.20
Royalties (11.43) (6.68) (12.76) (8.21)
Operating expenses (10.10) (11.83) (11.19) (11.69)
------------------------------------------
$ 34.34 $ 16.76 $ 34.92 $ 23.30
------------------------------------------
------------------------------------------


General and Administrative Expenses:

General and administrative expenses were $2.0 million or $2.90 per BOE for the three months ended September 30, 2008 compared to $1.6 million or $3.23 per BOE in the third quarter of 2007 and $1.8 million or $2.48 per BOE in the second quarter of 2008. General and administrative expenses were $5.4 million or $2.51 per BOE for the nine months ended September 30, 2008 compared to $4.9 million or $3.82 per BOE for the first nine months of 2007. General and administrative costs on a per BOE basis decreased from the same periods in the prior year as a result of increased production. General and administrative costs are expected to increase in the last quarter of 2008 as the Company has hired additional staff to manage its large upcoming winter drilling program.

Effective July 1, 2008, the Company initiated an Employee Stock Savings Plan ("ESSP"). Employees may contribute up to 5% of their base salaries towards the purchase of Company shares and the Company matches these contributions. Of eligible employees, over 93% are participating in the plan at an average contribution rate of 4.8% of base salary. The Company's matching expense for the three and nine months ended September 30, 2008 was $71,000 and is included in general and administrative expenses.



Three months ended Nine months ended
September 30 September 30
------------------------------------------
2008 2007 2008 2007

General and administrative (gross) $ 3,584 $ 2,565 $ 9,662 $ 8,015
Overhead recoveries (487) (326) (1,394) (1,055)
Capitalized (1,050) (656) (2,883) (2,028)
------------------------------------------
General and administrative (net) $ 2,047 $ 1,583 $ 5,385 $ 4,932
------------------------------------------
------------------------------------------

General and administrative ($/BOE) $ 2.90 $ 3.23 $ 2.51 $ 3.82

% G&A capitalized 29% 26% 30% 25%


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

Stock Based Compensation:

The Company accounts for stock-based compensation plans using the fair value method of accounting. Stock-based compensation costs were $0.4 million for the third quarter of 2008 ($0.2 million net of amounts capitalized) versus $0.3 million ($0.2 million net of amounts capitalized) in the third quarter of 2007. Stock-based compensation costs were $1.3 million for the first nine months of 2008 ($0.7 million net of amounts capitalized) versus $0.8 million ($0.4 million net of amounts capitalized) in the first nine months of 2007. The increase is a result of additional stock options being granted to new and existing staff members.

Interest Expense:

Interest expense was $1.0 million for the third quarter of 2008, compared to $1.2 million in the second quarter of 2008 and $0.6 million in the third quarter of the prior year. Interest expense was $3.4 million for the first nine months of 2008, compared to $1.6 million in comparable period in 2007. The increase in interest expense is due to the higher debt levels associated with the growth of the Company. Assets acquired in the second half of 2007 were also partially financed with debt. The average effective interest rate on outstanding bank loans was 4.7% for the three months ended September 30, 2008 compared to 6.1% for the three months ended September 30, 2007 and 5.1% for the nine months ended September 30, 2008 compared to 5.9% for the nine months ended September 30, 2007.

Depletion and Depreciation:

Depletion and depreciation was $20.28 per BOE for the third quarter of 2008 compared to $20.15 per BOE in the second quarter of 2008 and $20.75 per BOE in the third quarter of 2007. Depletion and depreciation was $20.21 per BOE for the first nine months of 2008 compared to $21.06 per BOE in the first nine months of 2007. Depletion and depreciation expense is calculated based on proved reserves only.

Asset Retirement Obligation:

The Company recorded $1.2 million in asset retirement obligations in the third quarter of 2008 and $3.0 million in the first nine months of 2008. Accretion expense was $0.5 million for the third quarter of 2008 compared to $0.4 million in the third quarter of 2007, and $1.4 million for the first nine months of 2008 compared to $0.9 million in the first nine months of 2007. Accretion expense was included in depletion and depreciation expense and increased due to new drilling, facilities construction and acquisitions.

Income Taxes:

Anderson Energy is not currently taxable. The Company has approximately $288 million in tax pools at September 30, 2008 and does not expect to be currently taxable in the near future based on current capital spending and price forecasts.

Funds from Operations:

Funds from operations for the third quarter of 2008 were $21.2 million ($0.24 per share), a 167% increase on a per share basis over the $6.3 million ($0.09 per share) recorded in the same period of the prior year and 23% lower on a per share basis than the $27.3 million ($0.31 per share) recorded in the second quarter of 2008. Funds from operations for the first nine months of 2008 were $66.1 million ($0.76 per share) compared to $23.9 million ($0.39 per share) recorded in the same period of the prior year. The increase in funds from operations is a result of higher production and higher commodity prices in 2008, partially offset by higher expenses.

Cash from operating activities also increased year over year for similar reasons. The reduction in non-cash working capital in the third quarter of 2008 reflects lower revenue accruals due to lower commodity prices when compared to the previous quarter.



Three months ended Nine months ended
September 30 September 30
(thousands of dollars) 2008 2007 2008 2007
------------------------------------------
Cash from operating activities $ 26,351 $ 5,801 $ 71,427 $ 23,149
Changes in non-cash working capital (5,656) 68 (5,956) 9
Asset retirement expenditures 517 386 653 692
------------------------------------------
Funds from operations $ 21,212 $ 6,255 $ 66,124 $ 23,850
------------------------------------------
------------------------------------------


Earnings:

The Company reported earnings of $4.2 million in the third quarter of 2008 compared to a loss of $3.0 million in the third quarter of 2007 and earnings of $8.5 million in the second quarter of 2008. The Company reported earnings of $14.4 million in the first nine months of 2008 compared to a loss of $2.7 million in the first nine months of 2007. Earnings were impacted by higher production and changes in commodity prices.

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:



Funds from Operations Earnings
Sensitivities: Millions Per Share Millions Per Share
------------------------------------------
$0.50/Mcf in price of natural gas $ 6.6 $ 0.08 $ 4.6 $ 0.05
US $5.00/bbl in the WTI crude price $ 1.8 $ 0.02 $ 1.3 $ 0.01
US $0.01 in the U.S./Cdn exchange
rate $ 1.4 $ 0.02 $ 1.0 $ 0.01
1% in short-term interest rate $ 1.1 $ 0.01 $ 0.8 $ 0.01


Capital Expenditures

The Company spent $27.1 million on capital expenditures in the third quarter of 2008 and $79.2 million in the nine months ended September 30, 2008. The breakdown of expenditures is shown below:



Three months ended Nine months ended
(thousands of dollars) September 30, 2008 September 30, 2008
---------------------------------------

Land, geological & geophysical
costs $ 395 $ 1,044
Property acquisitions, net of
dispositions 18 (857)
Drilling, completion and recompletion 17,831 42,362
Facilities and well equipment 7,724 33,612
Capitalized G&A 1,050 2,883
---------------------------------------
Total oil and natural gas expenditures 27,018 79,044
Office equipment and furniture 50 155
---------------------------------------
Total capital expenditures 27,068 79,199
Non-cash asset retirement obligations
and capitalized stock based
compensation 1,451 3,621
---------------------------------------
Total cash and non-cash capital
additions $ 28,519 $ 82,820
---------------------------------------
---------------------------------------

Drilling statistics are shown below:

Three months ended Nine months ended
September 30 September 30
----------------------------------------------------------
2008 2007 2008 2007
Gross Net Gross Net Gross Net Gross Net

Gas 34.0 21.2 29.0 20.1 110.0 75.2 69.0 45.8
Oil 2.0 2.0 2.0 0.7 6.0 2.9 5.0 2.2
Dry 3.0 2.0 3.0 2.5 10.0 8.1 8.0 4.7
----------------------------------------------------------
Total 39.0 25.2 34.0 23.3 126.0 86.2 82.0 52.7
----------------------------------------------------------
----------------------------------------------------------

Success rate (%) 92% 92% 91% 89% 92% 91% 90% 91%


During the third quarter of 2008, the Company participated in the drilling of 39 gross (25.2 net) wells of which 36 gross (23.2 net) were successful. The Company spent $7.7 million on facilities, which was comprised of the completion of three plant projects that were initiated in the second quarter and some well tie-ins.

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 11, 2008, there were 87.3 million common shares outstanding and 7.6 million stock options outstanding. The Company's market capitalization at November 11, 2008 was $154.5 million.



Three months ended Nine months ended
September 30 September 30
Share Price on TSX 2008 2007 2008 2007
---------------------------------------------------------

High $ 5.45 $ 4.97 $ 5.45 $ 5.40
Low $ 2.16 $ 3.67 $ 2.16 $ 3.35
Close $ 2.48 $ 3.74 $ 2.48 $ 3.74
Volume 13,233,544 10,405,724 66,274,841 27,341,078

Shares outstanding
at Sept 30 87,300,401 87,294,401 87,300,401 87,294,401
Market
capitalization at
Sept 30 $ 216,504,994 $ 326,481,060 $ 216,504,994 $ 326,481,060


Goodwill Assessment

No impairment in goodwill was assessed at September 30, 2008 based on the Company's estimate of net asset value. The assessment will be reviewed again at year end in light of more information on the longer term implications of global market conditions.

Liquidity and Capital Resources

At September 30, 2008, the Company had outstanding bank loans of $82.2 million and a working capital deficiency of $28.3 million. The large working capital deficiency is due to accruals associated with the capital program as well as operating expenses accrued but not yet billed.

The Company's 2008 capital program anticipates spending approximately $117 million in the field. This program is expected to be funded with a combination of debt, cash flow and property dispositions. To the end of the third quarter, the Company has sold $0.8 million in properties. In the fourth quarter of 2008, the Company has entered into letters of intent to sell $18 million in properties. With the significant, unprecedented changes in capital, equity, commodity and currency markets in the past few months and the ongoing concerns about the global credit crunch, the Company has reduced its originally planned 2008-2009 winter drilling program from 200 to 123 wells. The Company felt it was prudent to reduce its capital program given the uncertainty and volatility in world markets. Anderson Energy will continue to review the strength and direction of natural gas markets and the cost of services and make prudent adjustments to the winter drilling program as appropriate.

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, 2008, the Company has a $110.0 million extendible revolving term credit facility, a $10.0 million working capital credit facility and a $10.0 million supplemental credit facility with a syndicate of Canadian banks. The supplemental facility will expire on June 30, 2009. Anderson Energy will prudently use its bank loan facilities to finance its operations as required. The Company expects to have adequate liquidity to fund future working capital and the remaining 2008 capital expenditure program using a combination of cash flow, debt and asset sales.

Contractual Obligations

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

- Loan agreements - These reserves-based credit facilities have a revolving period ending July 14, 2009 extendible at the option of the lenders, followed by a term period with three equal quarterly principal repayments commencing 180 days from the term date.

- 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 2008, $1.8 million per year in 2009 through 2011, and $1.6 million in 2012.

- Firm service transportation commitments - The Company has entered into firm service transportation agreements for approximately 27.6 Mmcfd of gas sales for various terms expiring between 2008 and 2015.

In the fourth quarter of 2008, the Company entered into letters of intent to sell four properties in Alberta and two in British Columbia for total proceeds of $18 million before adjustments. The property sales are projected to reduce 2009 production by approximately 330 BOED. The property sales are subject to the execution of definitive purchase and sale agreements and normal closing conditions and are expected to close in late 2008 or early 2009.

Changes in Accounting Policies

On January 1, 2008, the Company adopted Section 1535 "Capital Disclosures". This section requires a discussion of the Company's objectives, policies and processes for managing capital including: quantitative data about what is considered capital, whether the entity has complied with any capital requirements and the consequences of non-compliance if the entity has not complied. These disclosures are included in note 5 of the accompanying consolidated financial statements.

On January 1, 2008, the Company also adopted the new Canadian standards for financial instruments: Section 3862 "Financial Instruments - Disclosures" and Section 3863 "Financial Instruments - Presentation", which apply to both recognized and unrecognized financial instruments. These disclosures include a discussion of the nature and extent of risks arising from financial instruments and are included in note 7 of the accompanying consolidated financial statements.

International Financial Reporting Standards ("IFRS")

In February 2008, the CICA Accounting Standards Board ("AcSB") confirmed the changeover to International Financial Reporting Standards ("IFRS") from Canadian GAAP will be required for publicly accountable enterprises' interim and annual financial statements effective for fiscal years beginning on or after January 1, 2011. The AcSB issued the "omnibus" exposure draft of IFRS with comments due by July 31, 2008, wherein early adoption by Canadian entities is also permitted. The Canadian Securities Administrators have also issued Concept Paper 52-402, which requested feedback on the early adoption of IFRS as well as the continued use of US GAAP by domestic issuers. The eventual changeover to IFRS represents a change due to new accounting standards. The transition from current Canadian GAAP to IFRS is a significant undertaking that may materially affect the Company's reported financial position and results of operations.

The International Accounting Standards Board issued an exposure draft on September 25, 2008, relating to certain amendments and exemptions to IFRS 1. One such exemption relating to full cost oil and gas accounting is expected to reduce the administrative burden in the transition from the current Canadian Accounting Guideline 16 to IFRS. It is anticipated that this exposure draft will not result in an amended IFRS 1 standard until late 2009. The amendment will permit the Company to apply IFRS prospectively to their full cost pool, rather than the retrospective assessment of capitalized exploration and development expenses, with the proviso that an impairment test, under IFRS standards, be conducted at the transition date.

Although, the Company has not completed development of its IFRS changeover plan, when finalized, it will include project structure and governance, resourcing and training, an analysis of key GAAP differences and a phased plan to assess accounting policies under IFRS as well as potential IFRS 1 exemptions. The Company anticipates completing its project scoping, which will include a timetable for assessing the impact on data systems, internal controls over financial reporting, and business activities, such as financing and compensation arrangements, by the end of 2008.

Disclosure Controls and Procedures

There were no material changes in the Company's internal controls over financial reporting during the nine months ended September 30, 2008.

Effective December 31, 2008, the Company will be required to certify on the operating effectiveness of internal controls over financial reporting. The Company is currently working on testing its controls to be able to provide this certification.

Business Risks

Oil and gas exploration and production is capital intensive and involves a number of business risks including 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, the U.S. dollar exchange rate, transportation costs, political stability and seasonal and weather related changes to demand. 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 filed with Canadian securities regulatory authorities on SEDAR.

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 ensures 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.

Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder to set legally binding targets to reduce nation-wide emissions of carbon dioxide, methane, nitrous oxide and other "greenhouse gases". In response to the Kyoto Protocol, the Canadian federal government introduced the Regulatory Framework for Air Emissions (the "Regulatory Framework") for regulating air pollution and industrial greenhouse gas ("GHG") emissions by establishing mandatory emissions reduction requirements on a sector basis. Sector-specific regulations are expected to come into force in 2010 and targets would be based on percentages rather than absolute reductions. The Regulatory Framework also proposes a credit emissions trading system. Additionally, regulation can take place at the provincial and municipal level. For example, Alberta introduced the Climate Change and Emissions Management Act, which provides a framework for managing GHG emissions by reducing specific gas emissions relative to gross domestic product to an amount that is equal to or less than 50% of 1990 levels by December 31, 2020 and which imposes duties to report. The accompanying regulation, the Specified Gas Emitters Regulation, effective July 1, 2007, requires mandatory emissions reductions through the use of emissions intensity targets. The Canadian federal government proposes to enter into equivalency agreements with provinces that establish a regulatory regime to ensure consistency with the federal plan, but the success of any such plan is doubtful in the current political climate, leaving multiple overlapping levels of regulation. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict the impact of the requirements on Anderson Energy and its operations and financial condition.

On October 25, 2007, the Alberta government announced proposed changes to the Alberta Crown royalty system that are expected to come into effect on January 1, 2009. The net impact on the Company will be higher royalties paid on natural gas liquids and crude oil. With 2007 natural gas prices, the Company would expect to pay lower Crown royalties on gas, as the Company is a low productivity per well producer. At natural gas prices in excess of $7.50 per Mcf, the Company would expect to pay higher Crown royalties on gas. Approximately 50% of the Company's royalties were paid to the Alberta Crown in 2007 and as such would have been affected by the changes.

Business Prospects

The Company has an excellent future drilling inventory with over five years of development drilling locations in its core resource plays, the Sylvan Lake Edmonton Sands and Horseshoe Canyon Coal Bed Methane.

Anderson Energy currently plans to drill 233 gross (145 net) wells in 2008, with the Edmonton Sands project representing 88% of the net drilling program. The 2008 capital budget is heavily weighted to the first and fourth quarters of the year to take advantage of lower costs on frozen ground conditions. The Company has completed three natural gas plant projects and brought these facilities on stream near the end of the second quarter, which is contributing to a reduction in operating expenses in the second half of the year. In addition, the Company continuously works with its suppliers and service companies to bring the cost of services down. The Company will continue to expand its drilling inventory through acquisitions and/or farm-ins in central Alberta.

The Company's 2008 average production guidance estimate has been reduced by 5% to approximately 7,800 BOED. This revision in guidance is due to less production than anticipated in the third quarter, delays in well tie-ins and third party curtailments in the Westpem area. Estimated 2008 guidance is a 46% increase over 2007 average production. Risks associated with this guidance include gas plant capacity, regulatory issues, weather problems and access to winter services.

Quarterly Information

The following table provides financial and operating results for the last eight quarters. The $117.6 million acquisition completed in September 2007 had a significant impact on capital spent in 2007 and on operating results in the fourth quarter of 2007 and first nine months of 2008. Commodity prices have been volatile since that time, which has had a significant impact on quarterly funds from operations and earnings.



SELECTED QUARTERLY INFORMATION
($ amounts in thousands, except per share amounts and prices)

Q3 2008 Q2 2008 Q1 2008 Q4 2007
-----------------------------------------
Oil and gas revenue before
royalties $ 39,427 $ 49,021 $ 37,695 $ 27,775
Funds from operations $ 21,212 $ 27,321 $ 17,591 $ 12,564
Funds from operations per share
Basic $ 0.24 $ 0.31 $ 0.20 $ 0.14
Diluted $ 0.24 $ 0.31 $ 0.20 $ 0.14
Earnings $ 4,160 $ 8,509 $ 1,696 $ 4,867
Earning per share
Basic $ 0.05 $ 0.10 $ 0.02 $ 0.06
Diluted $ 0.05 $ 0.10 $ 0.02 $ 0.06
Capital expenditures, including
acquisitions net of dispositions $ 27,068 $ 16,772 $ 35,359 $ 30,300
Cash from operating activities $ 26,351 $ 27,660 $ 17,416 $ 11,110
Daily sales
Natural gas (Mcfd) 38,703 39,881 39,210 35,672
Liquids (bpd) 1,221 1,265 1,345 1,150
BOE (bpd) 7,671 7,912 7,879 7,095
Average prices
Natural gas ($/Mcf) $ 7.86 $ 10.26 $ 7.55 $ 6.09
Liquids ($/bbl) $ 90.19 $ 97.61 $ 83.91 $ 72.28
BOE ($/BOE) $ 55.87 $ 68.08 $ 52.57 $ 42.55

Q3 2007 Q2 2007 Q1 2007 Q4 2006
-----------------------------------------
Oil and gas revenue before
royalties $ 17,261 $ 18,440 $ 20,109 $ 16,820
Funds from operations $ 6,255 $ 8,972 $ 8,623 $ 7,996
Funds from operations per share
Basic $ 0.09 $ 0.15 $ 0.16 $ 0.15
Diluted $ 0.09 $ 0.15 $ 0.16 $ 0.15
Earnings (loss) $ (3,018) $ 368 $ (33) $ 846
Earning (loss) per share
Basic $ (0.04) $ 0.01 $ - $ 0.02
Diluted $ (0.04) $ 0.01 $ - $ 0.02
Capital expenditures, including
acquisitions net of dispositions $ 135,966 $ 17,586 $ 27,281 $ 20,662
Cash from operating activities $ 5,801 $ 8,943 $ 8,405 $ 8,651
Daily sales
Natural gas (Mcfd) 26,860 22,928 22,162 21,075
Liquids (bpd) 843 602 750 692
BOE (bpd) 5,320 4,423 4,444 4,205
Average prices
Natural gas ($/Mcf) $ 5.00 $ 7.25 $ 8.14 $ 6.82
Liquids ($/bbl) $ 63.31 $ 58.18 $ 52.59 $ 51.09
BOE ($/BOE) $ 35.27 $ 45.81 $ 50.28 $ 43.48


Advisory

Certain information regarding Anderson Energy Ltd. in this news release including, without limitation, management's assessment of future plans and operations, number of locations in drilling inventory and wells to be drilled, timing of drilling and tie-in of wells and the costs thereof, productive capacity of the wells, timing of construction of facilities, expected production rates, dates of commencement of production, capital expenditures and timing thereof, value of undeveloped land, extent of reserve additions, ability to attain cost savings, drilling program success, impact of changes to the royalty regime applicable to the Company, commodity price outlook and future share performance, 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 reserve 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, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals 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), 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
(unaudited)
(stated in thousands of dollars)

----------------------------------------------------------------------------
----------------------------------------------------------------------------
September 30, December 31,
2008 2007
----------------------------------------------------------------------------

Assets

Current assets:
Cash $ 1 $ 2
Accounts receivable and accruals 28,287 31,540
Prepaid expenses and deposits 2,990 2,522
----------------------------------------------------------------------------
31,278 34,064

Property, plant and equipment (note 2) 501,614 461,896

Goodwill 35,364 35,364

----------------------------------------------------------------------------
$ 568,256 $ 531,324
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities and Shareholders' Equity

Current liabilities:
Accounts payable and accruals $ 59,623 $ 62,915

Bank loans (note 3) 82,190 67,981

Asset retirement obligations (note 4) 28,366 24,526

Future income taxes 47,967 41,450
----------------------------------------------------------------------------
218,146 196,872
Shareholders' equity:
Share capital (note 5) 334,176 334,147
Contributed surplus (note 5) 3,269 2,005
Retained earnings (deficit) 12,665 (1,700)
350,110 334,452

----------------------------------------------------------------------------
$ 568,256 $ 531,324
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


ANDERSON ENERGY LTD.
Consolidated Statements of Operations, Comprehensive Income (Loss) and
Retained Earnings (Deficit)
(unaudited)
(stated in thousands of dollars, except per share amounts)

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Nine months ended
September 30, September 30,
2008 2007 2008 2007
----------------------------------------------------------------------------
Revenues
Oil and gas sales $ 39,427 $ 17,261 $126,143 $ 55,810
Royalties (8,070) (3,270) (27,344) (10,606)
Interest income 8 224 53 285
----------------------------------------------------------------------------
31,365 14,215 98,852 45,489
Expenses
Operating 7,126 5,788 23,970 15,098
General and administrative 2,047 1,583 5,385 4,932
Stock-based compensation 232 158 692 416
Interest and other financing charges 980 589 3,373 1,609
Depletion, depreciation and
accretion 14,840 10,515 44,752 28,137
----------------------------------------------------------------------------
25,225 18,633 78,172 50,192
----------------------------------------------------------------------------
Earnings (loss) before taxes 6,140 (4,418) 20,680 (4,703)
Future income taxes (reduction) 1,980 (1,400) 6,315 (2,020)
----------------------------------------------------------------------------
Earnings (loss) for the period 4,160 (3,018) 14,365 (2,683)
Reclassification of accumulated
other comprehensive income to
earnings - - - (1,465)
----------------------------------------------------------------------------
Comprehensive income (loss) $ 4,160 $ (3,018) $ 14,365 $ (4,148)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Retained earnings (deficit),
beginning of period $ 8,505 $ (3,549) $ (1,700) $ (3,884)
Earnings (loss) for the period 4,160 (3,018) 14,365 (2,683)
----------------------------------------------------------------------------
Retained earnings (deficit), end of
period $ 12,665 $ (6,567) $ 12,665 $ (6,567)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Earnings (loss) per share (note 5)
Basic $ 0.05 $ (0.04) $ 0.16 $ (0.04)
Diluted $ 0.05 $ (0.04) $ 0.16 $ (0.04)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.


ANDERSON ENERGY LTD.
Consolidated Statements of Cash Flows
(unaudited)
(stated in thousands of dollars)

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Nine months ended
September 30, September 30,
2008 2007 2008 2007
----------------------------------------------------------------------------

Cash provided by (used in):

Operations
Earnings (loss) for the period $ 4,160 $ (3,018) $ 14,365 $ (2,683)
Items not involving cash
Depletion, depreciation and
accretion 14,840 10,515 44,752 28,137
Future income tax taxes (reduction) 1,980 (1,400) 6,315 (2,020)
Stock-based compensation 232 158 692 416
Asset retirement expenditures (517) (386) (653) (692)
Changes in non-cash working capital
Accounts receivable and accruals 7,532 384 (47) (971)
Prepaid expenses and deposits (92) (968) (615) (955)
Accounts payable and accruals (1,784) 516 6,618 1,917
----------------------------------------------------------------------------
26,351 5,801 71,427 23,149

Financing
Increase in bank loans 1,027 29,354 14,209 28,463
Issue of common shares - 94,719 25 127,282
----------------------------------------------------------------------------
1,027 124,073 14,234 155,745

Investments
Additions to property, plant and
equipment (27,050) (17,963) (80,056) (63,636)
Acquisition of 3210700 Nova Scotia
Company - (117,634) - (117,634)
Payment of liabilities assumed on
acquisition - (324) - (324)
Proceeds on disposition of
properties (18) (45) 857 761
Changes in non-cash working capital
Accounts receivable and accruals (4,075) (2,981) 3,300 1,902
Prepaid expenses and deposits 27 (21) 147 (119)
Accounts payable and accruals 3,621 9,085 (9,910) 146
----------------------------------------------------------------------------
(27,495) (129,883) (85,662) (178,904)

----------------------------------------------------------------------------
Decrease in cash (117) (9) (1) (10)

Cash, beginning of period 118 10 2 11
----------------------------------------------------------------------------

Cash, end of period $ 1 $ 1 $ 1 $ 1
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.


ANDERSON ENERGY LTD.
Notes to the Consolidated Financial Statements
Three and Nine months ended September 30, 2008 and 2007
(unaudited)
(tabular amounts in thousands of dollars, unless otherwise stated)


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, 2007, except as disclosed below. 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, 2007.

1. Change in accounting policies

On January 1, 2008, the Company adopted Section 1535 "Capital Disclosures". This section requires a discussion of the Company's objectives, policies and processes for managing capital including: quantitative data about what is considered capital, whether the entity has complied with all capital requirements and the consequences of non-compliance if the entity has not complied. These disclosures are included in note 5.

On January 1, 2008, the Company also adopted the new Canadian accounting standards for financial instruments: Section 3862 "Financial Instruments - Disclosures" and Section 3863 "Financial Instruments - Presentation", which apply to both recognized and unrecognized financial instruments. These disclosures include a discussion of the nature and extent of risks arising from financial instruments and are included in note 7.

Future accounting changes

In February 2008, the CICA Accounting Standards Board ("AcSB") confirmed the changeover to International Financial Reporting Standards ("IFRS") from Canadian Generally Accepted Accounting Principles ("GAAP") will be required for publicly accountable enterprises' interim and annual financial statements effective for fiscal years beginning on or after January 1, 2011. The AcSB issued the "omnibus" exposure draft of IFRS with comments due by July 31, 2008, wherein early adoption by Canadian entities is also permitted. The Canadian Securities Administrators have also issued Concept Paper 52-402, which requested feedback on the early adoption of IFRS as well as the continued use of US GAAP by domestic issuers. The eventual changeover to IFRS represents a change due to new accounting standards. The transition from current Canadian GAAP to IFRS is a significant undertaking that may materially affect the Company's reported financial position and results of operations.

The International Accounting Standards Board issued an exposure draft on September 25, 2008, relating to certain amendments and exemptions to IFRS 1. One such exemption relating to full cost oil and gas accounting is expected to reduce the administrative burden in the transition from the current Canadian Accounting Guideline 16 to IFRS. It is anticipated that this exposure draft will not result in an amended IFRS 1 standard until late 2009. The amendment will permit the Company to apply IFRS prospectively to their full cost pool, rather than the retrospective assessment of capitalized exploration and development expenses, with the proviso that an impairment test, under IFRS standards, be conducted at the transition date.

Although, the Company has not completed development of its IFRS changeover plan, when finalized, it will include project structure and governance, resourcing and training, an analysis of key GAAP differences and a phased plan to assess accounting policies under IFRS as well as potential IFRS 1 exemptions. The Company anticipates completing its project scoping, which will include a timetable for assessing the impact on data systems, internal controls over financial reporting, and business activities, such as financing and compensation arrangements, by the end of 2008.



2. Property, plant and equipment
----------------------------------------------------------------------------
----------------------------------------------------------------------------
September 30, December 31,
2008 2007
----------------------------------------------------------------------------
Cost $ 656,024 $ 573,002
Less accumulated depletion and depreciation (154,410) (111,106)
----------------------------------------------------------------------------
Net book value $ 501,614 $ 461,896
----------------------------------------------------------------------------
----------------------------------------------------------------------------


At September 30, 2008, unproved property costs of $16.9 million (December 31, 2007 - $16.1 million) have been excluded from the full cost pool for depletion and depreciation calculations. Future development costs of proved, undeveloped reserves of $164.3 million (December 31, 2007 - $177.8 million) have been included in the depletion and depreciation calculation.

For the three months ended September 30, 2008, $1.3 million (September 30, 2007 - $0.8 million) of general and administrative costs including $0.2 million (September 30, 2007 - $0.1 million) of stock-based compensation costs were capitalized. For the nine months ended September 30, 2008, $3.6 million (September 30, 2007 - $2.4 million) of general and administrative costs including $0.6 million (September 30, 2007 - $0.4 million) of stock-based compensation costs were capitalized. The future tax liability of $0.2 (September 30, 2007 - $0.2) associated with the capitalized stock-based compensation has also been 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, 2008. The future commodity prices used in the ceiling test were based on commodity price forecasts of the Company's independent reserves engineers adjusted for differentials specific to the Company's reserves.

3. Bank loans

At September 30, 2008, total bank facilities were $130 million. The Company has a $110 million extendible, revolving term credit facility and a $10 million working capital credit facility (the "Facilities") with a syndicate of Canadian banks. The reserves-based Facilities have a revolving period ending on July 14, 2009, extendible at the option of the lenders, followed by a term period with three equal quarterly principal repayments commencing 180 days from the term date. The Company also has a $10 million supplemental credit facility (the "Supplemental Facility") with the existing syndicate of Canadian banks. The Supplemental Facility is in addition to the Facilities noted above and is available on a revolving basis. The Supplemental Facility shall be repaid in full on or before June 30, 2009.

Advances under the Facilities and Supplemental Facility 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, 2008, there were no advances under the Supplemental Facility and there were no advances in U.S. funds. The average effective interest rate on advances in 2008 was 5.1% (September 30, 2007 - 5.9%).

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

4. Asset retirement obligations

The Company estimates the total undiscounted cash flows required to settle its asset retirement obligations is approximately $60.2 million (December 31, 2007 - $52.2 million), including expected inflation of 2% (December 31, 2007 - 2%) per annum. The majority of the costs will be incurred between 2008 and 2020. A credit adjusted risk-free rate of 8% (December 31, 2007 - 8%) 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,
2008 2007
----------------------------------------------------------------------------
Balance, beginning of period $24,526 $14,905
Liabilities incurred during period 3,045 3,060
Liabilities assumed on corporate acquisition - 5,923
Liabilities settled in period (653) (742)
Accretion expense 1,448 1,380
----------------------------------------------------------------------------
Balance, end of period $28,366 $24,526
----------------------------------------------------------------------------
----------------------------------------------------------------------------


5. 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 Amount
Shares (thousands)
----------------------------------------------------------------------------
Balance at December 31, 2006 53,641,401 $208,994
Issued pursuant to prospectuses (1) 33,635,000 134,747
Share issue costs - (7,537)
Tax effect of share issue costs - 2,329
Stock options exercised 18,000 72
Tax effect of flow-through shares issued in 2006 - (4,458)
----------------------------------------------------------------------------
Balance at December 31, 2007 87,294,401 334,147
Stock options exercised 6,000 25
Transferred from contributed surplus on stock
option exercise - 4
----------------------------------------------------------------------------
Balance at September 30, 2008 87,300,401 $334,176
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes 344,494 common shares shares issued to management and
directors.


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, 2008 and year ended December 31, 2007 are as follows:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted
average
Number of exercise
options price
----------------------------------------------------------------------------
Balance at December 31, 2006 4,830,406 $ 4.89
Granted 1,531,500 3.94
Exercised (18,000) 4.00
Expirations and forfeitures (46,600) 7.28
----------------------------------------------------------------------------
Balance at December 31, 2007 6,297,306 4.65
Granted 1,418,200 3.24
Exercised (6,000) 4.13
Expirations and forfeitures (112,450) 4.45
----------------------------------------------------------------------------
Balance at September 30, 2008 7,597,056 $ 4.39
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Exercisable at September 30, 2008 4,603,756 $ 4.68
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Options outstanding Options exercisable
-----------------------------------------------------------
Weighted Weighted Weighted
average average average
Range of Number exercise remaining Number of exercise
exercise prices of options price life (years) options price
----------------------------------------------------------------------------
$2.66 to $3.75 996,300 $ 2.77 5.0 - -
$3.76 to $5.00 5,332,356 4.02 3.8 3,665,556 $ 4.00
$5.01 to $7.50 543,000 6.15 2.7 376,000 6.15
$7.51 to $9.01 725,400 8.01 2.1 562,200 8.12
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Total at September
30, 2008 7,597,056 $ 4.39 3.7 4,603,756 $ 4.68
----------------------------------------------------------
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The fair value of the options issued during the period ended September 30, 2008 ranged between $1.43 to $2.75 per option (September 30, 2007 - $1.59 to $1.99 per option). The weighted average assumptions used in arriving at the values were: a risk-free interest rate of 3.2% (September 30, 2007 - 4.4%), expected option life of five years, expected volatility of 56% (September 30, 2007 - 40%) and a dividend yield of 0%.

Per share amounts

During the three months ended September 30, 2008 there were 87,300,401 weighted average shares outstanding (September 30, 2007 - 70,254,184). On a diluted basis, there were 87,300,401 weighted average shares outstanding (September 30, 2007 - 70,254,184) after giving effect to dilutive stock options. During the nine months ended September 30, 2008 there were 87,297,270 weighted average shares outstanding (September 30, 2007 - 61,222,134). On a diluted basis, there were 87,399,611 weighted average shares outstanding (September 30, 2007 - 61,222,134) after giving effect to dilutive stock options. At September 30, 2008, there were 7,597,056 options that were anti-dilutive (September 30, 2007 - 3,576,900).



Contributed surplus

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Amount
----------------------------------------------------------------------------
Balance at December 31, 2006 $ 820
Stock-based compensation 1,185
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Balance at December 31, 2007 2,005
Stock-based compensation 1,268
Transferred from contributed surplus on stock option exercise (4)
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Balance at September 30, 2008 $3,269
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Employee stock savings plan

Effective July 1, 2008, the Company initiated an Employee Stock Savings Plan ("ESSP"). Employees may contribute up to 5% of their base salaries towards the purchase of Company shares and the Company matches these contributions. The Company's matching contribution for the three and nine months ended September 30, 2008 was $71,000 and is included in general and administrative expenses.

Management of capital structure

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

The Company manages its capital structure and makes adjustments to it in the light of changes in economic conditions and the risk characteristics of the underlying petroleum and natural gas assets. The Company's capital structure includes shareholders' equity of $350.1 million, bank loans of $82.2 million and the working capital deficiency of $28.3 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.

As a result of the global economic downturn, there is uncertainty in capital markets and, as a result, the Company anticipates that it and others in the oil and gas sector will have limited access to capital and an increased cost of capital. Although the business and assets of the Company have not changed, financial institutions and investors have increased their risk premiums and their overall lending capacity and equity investment has diminished. The Company continually monitors its financing alternatives, and expects to finance its 2008 capital expenditures program from internally generated funds from operations and non-core property sales.

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 bank loans) by the annualized current quarter funds from operations (before changes in non-cash working capital and asset retirement expenditures). The Company's strategy is to maintain a ratio of total debt to annualized funds from operations under 2 times. This ratio may increase above this at certain times as a result of acquisitions and timing of capital expenditures. 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.



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September 30, December 31,
2008 2007
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Bank loans $ 82,190 $ 67,981
Current liabilities 59,623 62,915
Current assets (31,278) (34,064)
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Total debt $110,535 $ 96,832
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Cash from operating activities in quarter $ 26,351 $ 11,110
Changes in non-cash working capital (5,656) 1,404
Asset retirement expenditures 517 50
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Funds from operations in quarter $ 21,212 $ 12,564
Annualized current quarter funds from
operations $ 84,848 $ 50,256
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Total debt to funds from operations 1.3 1.9
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At September 30, 2008, the Company's total debt to annualized funds from operations was 1.3 times, which is within the established range. At December 31, 2007, the Company's total debt to annualized funds from operations was 1.9 times, also within the established range. In the third quarter of 2007, Anderson Energy completed a significant oil and gas asset acquisition which was partially financed with debt. The Company's capital program is also heavily weighted to the winter months and this ratio will tend to be higher during that time of the year.

The Company's share capital is not subject to external restrictions, however, the Facilities and Supplemental Facility are petroleum and natural gas reserves based (see note 3). 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):



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September 30, September 30,
2008 2007
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Interest paid $2,708 $1,864
Interest received (56) (290)
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7. Financial instruments and financial risk management

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

The Company's risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company's activities.

The Company has exposure to credit risk, liquidity risk and market risk as a result of its use of financial instruments. This note presents information about the Company's exposure to each of the above risks and the Company's objectives, policies and processes for measuring and managing these risks. Further quantitative disclosures are included throughout these financial statements.

The Board of Directors has overall responsibility for the establishment and oversight of the Company's risk management framework. The Board has implemented and monitors compliance with risk management policies.

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. A substantial portion of the Company's accounts receivable are with natural gas and liquids marketers and joint venture partners in the oil and gas industry and are subject to normal industry credit risks. Purchasers of the Company's natural gas and liquids are subject to credit review to minimize the risk of non-payment. As at September 30, 2008, the maximum credit exposure is the carrying amount of the accounts receivable and accruals of $28.3 million (December 31, 2007 - $31.5 million). As at September 30, 2008, the Company's receivables consisted of $16.2 million from joint venture partners and other trade receivables and $12.1 million of revenue accruals and other receivables from petroleum and natural gas marketers.

Receivables from petroleum and natural gas marketers are typically collected on the 25th day of the month following production. The Company's policy to mitigate credit risk associated with these balances is to establish marketing relationships with large purchasers. The Company historically has not experienced any significant collection issues with its petroleum and natural gas marketers. Of the $12.1 million of revenue accruals and receivables from petroleum and natural gas marketers, $9.6 million was received on or about October 25, 2008. The balance is expected to be received in subsequent months through joint venture billings from partners.

Joint venture receivables are typically collected within one to three months of the joint venture bill being issued to the partner. The Company mitigates the risk from joint venture receivables by obtaining partner approval of capital expenditures prior to starting a project. However, the receivables are from participants in the petroleum and natural gas sector, and collection is dependent on typical industry factors such as commodity price fluctuations, escalating costs and the risk of unsuccessful drilling. Further risk exists with joint venture partners, as disagreements occasionally arise that increase the potential for non-collection. For properties that are operated by Anderson Energy, production can be withheld from joint venture partners who are in default of amounts owing. In addition, the Company often has offsetting amounts payable to joint venture partners from which it can net receivable balances. As at September 30, 2008, the largest amount owing from one partner is $3.6 million.

The Company is from time to time exposed to credit risk associated with possible non-performance by counterparties to derivative financial instrument contracts. The Company believes these risks to be minimal as the counterparties are major financial institutions.

The Company's allowance for doubtful accounts as at September 30, 2008 is $1.3 million. This allowance was created in prior years and is associated with prior corporate acquisitions and potential joint venture billing disputes. The Company did not provide for any additional doubtful accounts nor was it required to write-off any receivables during the period ended September 30, 2008. The Company would only choose to write-off a receivable balance (as opposed to providing an allowance) after all reasonable avenues of collection had been exhausted.

As at September 30, 2008 the Company considers it receivables to be aged as follows:



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Aging September 30, 2008
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Not past due $ 22,780
Past due by less than 120 days 1,035
Past due by more than 120 days 4,472
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Total $ 28,287
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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 Company's approach to managing liquidity is to ensure, as far as possible, that it will have sufficient liquidity to meet its liabilities when due, under both normal and stressed conditions without incurring unacceptable losses or risking harm to the Company's reputation.

The Company prepares annual capital expenditure budgets, which are regularly monitored and updated as considered necessary. The Company uses authorizations for expenditures on both operated and non-operated projects to further manage capital expenditures. To facilitate the capital expenditure program, the Company has revolving reserves based credit facilities, as outlined in note 3, which are reviewed at least annually by the lenders. The Company monitors its total debt position monthly. The Company also attempts to match its payment cycle with collection of petroleum and natural gas revenues on the 25th of each month. The Company anticipates it will have adequate liquidity to fund its financial liabilities through its future cash flows.

The following are the contractual maturities of financial liabilities and associated interest payments as at September 30, 2008:



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Financial Liabilities less than 1 Year 1 -2 Years
----------------------------------------------------------------------------
Accounts payable and accrued liabilities $ 59,623 $ -
Bank debt - principal - 82,190
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Total $ 59,623 $ 82,190
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Market risk

Market risk consists of currency risk, commodity price risk and interest rate risk. The objective of market risk management is to manage and control market risk exposures within acceptable limits, while maximizing returns.

The Company may use both financial derivatives and physical delivery sales contracts to manage market risks. All such transactions are conducted in accordance with a risk management policy that has been approved by the Board of Directors.

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. Substantially all of the Company's petroleum and natural gas sales are denominated in Canadian dollars, however, the underlying market prices in Canada for petroleum and natural gas are impacted by changes in the exchange rate between the Canadian and United States dollar. From time to time in 2007 and 2008, the Company chose to sell a portion of its oil in United States dollars.

The Company had no outstanding forward exchange rate contracts in place at September 30, 2008.

Commodity price risk

Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for petroleum and natural gas are impacted by world economic events that dictate the levels of supply and demand as well as the relationship between the Canadian and United States dollar, as outlined above. The Company may mitigate commodity price risk through the use of financial derivatives and physical delivery fixed price sales contracts. All such contracts require approval of the Board of Directors.

On January 10, 2008, the Company entered into physical sales contracts to sell 25,000 GJ/day for February and March 2008 at an average AECO price of $6.89/GJ. The losses realized to September 30, 2008 were $1.3 million and have been included in oil and gas sales.

In 2007, the Company also entered into certain fixed price natural gas financial swap contracts. The gains realized for the nine months ended September 30, 2007 were $1.2 million and were included in oil and gas sales.

There were no commodity price risk contracts outstanding at September 30, 2008.

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, 2008, if interest rates had been 1% lower with all other variables held constant, earnings for the period would have been $0.4 million (September 30, 2007 - $0.2 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 impact is greater for 2008 as compared to 2007 due to higher average debt levels in 2008.

The Company had no interest rate swap or financial contracts in place at September 30, 2008.



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) 206-6000
Canada T2P 3E7
Phone (403) 262-6307
Fax (403) 261-2792
Website www.andersonenergy.ca

Directors Officers

J.C. Anderson (1)(2) J.C. Anderson
Calgary, Alberta Chairman of the Board

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

Vincent L. Chahley (1)(2)(3) M. Darlene Wong
Calgary, Alberta Vice President Finance, Chief Financial
Officer & Secretary
Glenn D. Hockley (3)
Calgary, Alberta Blaine M. Chicoine
Vice President, Operations
David G. Scobie (1)(2)(3)
Calgary, Alberta Philip A. Harvey
Vice President, Exploitation
Member of:
(1) Audit Committee Daniel F. Kell
(2) Compensation & Corporate Vice President, Land
Governance Committee
(3) Reserves Committee Jamie A. Marshall
Vice President, Exploration

Auditors David M. Spyker
KPMG LLP Vice President, Business Development
Calgary, Alberta

Independent Engineers
AJM Petroleum Consultants

Legal Counsel
Bennett Jones LLP

Registrar & Transfer Agent
Valiant Trust Company

Stock Exchange
The Toronto Stock Exchange
Symbol AXL


Abbreviations used:

AECO - intra-Alberta Nova inventory transfer price
AOF - absolute open flow potential
bbl - barrel
bpd - barrels per day
Mbbls - thousand barrels
BOE - barrels of oil equivalent
BOED - barrels of oil equivalent per day
MBOE - thousand barrels of oil equivalent
MMBOE - million barrels of oil equivalent
CBM - Coal Bed Methane
GJ - gigajoule
Mcf - thousand cubic feet
Mcfd - thousand cubic feet per day
MMcf - million cubic feet
MMcfd - million cubic feet per day
Bcf - billion cubic feet
Tcf - trillion cubic feet
MMbtu - million British thermal units

Contact Information

  • Anderson Energy Ltd.
    Brian H. Dau
    President & Chief Executive Officer
    (403) 206-6000
    (403) 261-2792 (FAX)
    Website www.andersonenergy.ca