Anderson Energy Ltd.
TSX : AXL

Anderson Energy Ltd.

August 13, 2008 09:00 ET

Anderson Energy Ltd. Announces 2008 Second Quarter Results

CALGARY, ALBERTA--(Marketwire - Aug. 13, 2008) - Anderson Energy Ltd. ("Anderson Energy" or the "Company") (TSX:AXL) is pleased to announce its operating and financial results for the second quarter ended June 30, 2008.

Highlights

- Funds from operations for the second quarter tripled to $27.3 million ($0.31 per share) compared to the second quarter of 2007. On a per share basis, it doubled from the second quarter of 2007 and was 55% higher than the first quarter of 2008. Funds from operations for the six months ended June 30, 2008 were $44.9 million ($0.51 per share) as compared to $17.6 million ($0.31 per share) for the same six months in 2007 and $36.4 million ($0.54 per share) for the full year ended December 31, 2007.

- Second quarter production averaged 7,912 BOED, 79% higher than the second quarter of 2007. Current production is 8,200 BOED with behind pipe production capability of an additional 1,100 BOED.

- The Company realized an average natural gas price of $10.26 per Mcf. The Company was unhedged in the second quarter.

- The Company completed three 100% owned and operated natural gas plant projects near the end of the second quarter at an estimated total cost of $14.0 million. These projects are designed to bring down operating costs in the second half of the year.

- The Company's future drilling inventory is 1,154 gross (588 net) wells as of June 30, 2008, based on a four well per section Edmonton Sands drilling density.

- The 2008 capital budget increased from $85.0 million to $117.0 million to accommodate additional Edmonton Sands drilling in the fourth quarter of 2008. The increase in capital spending is expected to be funded from cash flow and an expansion of the existing bank lines. The spending will occur largely in the fourth quarter of the year. With this budget expansion, the Company is planning to drill 246 gross (165 net) wells in 2008.




Financial and Operating Highlights

Three months Six months
ended % ended %
June 30 Change June 30 Change
-------------------------------------------------
2008 2007 2008 2007

Financial

(thousands of dollars,
except share data)

Total oil and gas revenue $ 49,021 $ 18,440 166% $ 86,716 $ 38,549 125%

Funds from operations $ 27,321 $ 8,972 205% $ 44,912 $ 17,595 155%
Per common share - basic $ 0.31 $ 0.15 107% $ 0.51 $ 0.31 65%
- diluted $ 0.31 $ 0.15 107% $ 0.51 $ 0.31 65%

Earnings $ 8,509 $ 368 2212% $ 10,205 $ 335 2946%
Per common share - basic $ 0.10 $ 0.01 900% $ 0.12 $ 0.01 1100%
- diluted $ 0.10 $ 0.01 900% $ 0.12 $ 0.01 1100%

Field capital expenditures 17,647 8,441 109% 53,006 36,465 45%
Acquisitions, net of
dispositions (875) 9,145 (110%) (875) 8,402 (110%)

Debt, net of working
capital 104,162 43,668 139%

Shareholders' equity $345,501 $235,483 47%

Average shares outstanding
(thousands)
Basic 87,297 59,588 47% 87,296 56,631 54%
Diluted 87,604 60,059 46% 87,603 57,104 53%

Ending shares outstanding
(thousands) 87,300 61,594 42%

Operating (6 Mcf:1bbl
conversion)

Average daily sales
Natural gas (Mcfd) 39,881 22,928 74% 39,546 22,547 75%
Light/medium crude oil
(bpd) 436 504 (13%) 512 537 (5%)
NGL (bpd) 829 98 746% 793 139 471%
Barrels of oil equivalent
(BOED) 7,912 4,423 79% 7,896 4,434 78%

Average sales price
Natural gas ($/Mcf) 10.26 7.25 42% 8.92 7.68 16%
Light/medium crude oil
($/bbl) 115.48 58.07 99% 101.50 55.82 82%
NGL ($/bbl) 88.21 58.71 50% 83.48 52.26 60%
Barrels of oil equivalent
($/BOE) 68.08 45.81 49% 60.35 48.04 26%

Royalties ($/BOE) 14.70 7.37 99% 13.41 9.14 47%
Operating costs ($/BOE) 11.32 10.97 3% 11.72 11.60 1%
Operating netbacks ($/BOE) 42.06 27.47 53% 35.22 27.30 29%
General and administrative
($/BOE) 2.48 4.18 (41%) 2.32 4.17 (44%)

Wells drilled (gross) 1 5 (80%) 87 48 81%


Operating Highlights

Production:

In the second quarter of 2008, production averaged 7,912 BOED, an increase of 79% over the second quarter of 2007 and slightly higher than the first quarter of 2008. The Company experienced plant outages at various facilities in the month of June. The time to construct the Willesden Green facility was longer than anticipated due to wet weather conditions. The Willesden Green facility construction was a modification of the existing field compression into a refrigeration natural gas plant. This entire facility was down for almost seven weeks, causing a reduction in production of 500 BOED in the month of June and for the first part of July. On July 10, 2008, the new facility was commissioned and production has resumed at previous levels. The Company had planned to tie-in 23 wells in May, however due to wet weather conditions, these well tie-ins were delayed until the third quarter. Current production is 8,200 BOED, with behind pipe production capability of 1,100 BOED.

The Company's funds from operations in the second quarter were $27.3 million and earnings were $8.5 million. This compares to funds from operations of $9.0 million and earnings of $0.4 million in the second quarter of 2007 and $17.6 million and $1.7 million respectively in the first quarter of 2008. Natural gas prices were $10.26 per Mcf in the second quarter of 2008, compared to $7.25 per Mcf in the second quarter of 2007 and $7.55 per Mcf in the first quarter of 2008. Since the end of the quarter, natural gas prices have pulled back with current AECO spot prices being approximately $7.55 per Mcf. Crude oil and natural gas liquids prices were substantially stronger in the second quarter with an average price of $97.61 per bbl in the second quarter of 2008 compared to $58.18 per bbl in the second quarter of 2007. The Company's operating netback was $42.06 per bbl in the second quarter of 2008 compared to $27.47 per bbl in the second quarter of 2007 and $28.32 per bbl in the first quarter of 2008, due to increased product prices.

Capital Program:

Capital expenditures were $16.8 million during the quarter, of which $14.2 million was spent on facilities.

As expected, during the second quarter of 2008, the Company was not actively drilling in the field, with only one gross (0.2 net) non-operated Horseshoe Canyon CBM well drilled in the Ghost Pine area.

Near the end of the second quarter, the Company completed three 100% owned and operated natural gas plant/compressor station projects. The Buck Lake compressor station came on stream on June 23, 2008, the Willesden Green refrigeration plant came on stream on July 10, 2008 and the Wilson Creek compressor station came on stream on July 16, 2008. These plant projects were designed to bring down operating expenses in the second half of the year and to provide increased capacity for production generated from next winter's drilling program.

In the third quarter, to August 12, 2008, the Company has drilled four gross Mannville locations and 13 gross Edmonton Sands locations with a total success rate of 100%.

Dispositions:

In the second quarter of 2008, the Company completed the sale of $0.8 million in non-core assets. The Company was unable to close the sale of an additional $6.7 million in non-core assets. The Company is continuing to market these assets.

Bank Lines:

The Company has received approval from its lenders to increase its extendible, revolving term credit facility by $15 million to $110 million. The working capital facility remains at $10 million. The supplemental facility, which was originally scheduled to reduce to $10 million on September 30, 2008 and expire on December 31, 2008, has been extended to June 30, 2009 at $10 million. The total bank facilities are $130 million. The amendments are subject to completion of customary loan and security documentation. The bank facilities were modified to accommodate a 200 well Edmonton Sands drilling program in the upcoming winter.

Outlook:

On January 11, 2008, the Company announced a preliminary budget of $60.0 million, which at that time represented a cash flow budget based on a corporate average natural gas price of $6.50 per Mcf. With the significant improvement in current natural gas prices and the natural gas price outlook, the Company increased its 2008 budget to $85.0 million on May 13, 2008. On August 12, 2008 the Board of Directors elected to increase the 2008 capital program to $117.0 million. The capital program is being funded with cash flow and bank lines. As with previous expansions of the capital program, the capital spending emphasis will be on the fourth quarter. With the budget expansion, the Company plans to drill a total of 246 gross (165 net) wells in 2008.

The Company has been very active in the field acquiring drilling licences and pipeline right of ways to drill 120 Edmonton Sands wells in the fourth quarter as part of its planned 200 well Edmonton Sands winter program. The Company expects to drill 20 gross (13.7 net) Edmonton Sands locations and eight gross (6.5 net) Mannville locations in the third quarter. The Company also plans to drill three 100% working interest Rock Creek infill wells in Westpem in the balance of the year. A third party pipeline is being built into the Westpem area to alleviate capacity constraints and is expected to be on stream near the end of the year.

The Company initiated a test to restart the Chedderville Leduc A sour gas pool on July 31, 2008. When acquired in 2007, this field was substantially shut-in due to a lack of water handling facilities. The Company is planning to test four wells individually through newly installed rental compression to determine the individual well capability for gas and water, where the gas will be sold and the water will be trucked. The first well has been testing for the past 13 days and initial results are encouraging. If this test is successful, this field could be commercially brought back on production in 2009 with the installation of water handling/disposal facilities. The central Alberta Mannville, Westpem Rock Creek and Chedderville projects were generated from the lands acquired last year in the September 2007 acquisition.

As of June 30, 2008, the Company has identified 1,154 gross (588 net) drilling locations of which 87% 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 expects it could take approximately five years to drill these 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 significantly grown its Edmonton Sands land position on a net section basis from 303 gross (179 net) sections at December 31, 2007 to 323 gross (195 net) sections as of August 1, 2008.

In the balance of the year, the Company expects to expand its drilling inventory through acquisitions and/or farm-ins in central Alberta. The Company will also be carefully examining potential property and corporate acquisitions in 2008.

The outlook for natural gas has proven to be volatile in the last few months. However the fundamentals for the natural gas business are still sound with the United States natural gas storage being 12.3% less than the previous year and 0.2% lower than the five year average. The NYMEX natural gas futures market prices for next winter are in the US$9.50 per MMbtu range.

We are pleased to announce the promotion of Jamie Marshall to Vice President, Exploration. Jamie joined Anderson Energy in 2004 and was previously Manager, Exploration.

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

August 12, 2008

Management's Discussion and Analysis

For the Three and Six Months Ended June 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 six months ended June 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 August 12, 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 news release.

Review of Financial Results

Overview:

Sales volumes for the three months ended June 30, 2008 averaged 7,912 BOED, similar to the first quarter of 2008. The Company had plant outages at various facilities in the month of June that were longer than or in addition to what was initially anticipated. The most significant of these was at the Willesden Green facility where new construction resulted in the shut-in of 500 BOED for the full month of June and part of July. In addition, the Company planned to tie-in 23 wells in the month of May, however, due to wet weather conditions, the tie-in of these wells was delayed until the third quarter of 2008. Stronger natural gas and crude oil prices and lower operating costs increased funds from operations for the three months ended June 30, 2008 to $27.3 million, 55% higher than the first quarter of 2008.

Capital expenditures were $16.8 million for the three months ended June 30, 2008. During the second quarter of 2008, the Company drilled 1 gross (0.2 net) well, which was successful. The Company spent $14.2 million on facilities in the quarter, completing three natural gas plant/compressor station projects.

Debt, net of working capital, was $104.2 million at June 30, 2008, lower than at March 31, 2008 as a result higher funds from operations and lower capital expenditures. The Company's initial 2008 capital program was weighted to the first quarter of the year. The Company has expanded its 2008 capital budget from $85.0 million to $117.0 million. The program will include a 200 well Edmonton Sands drilling program in the winter of 2008/2009. Capital spending will be heavily weighted to the fourth quarter of 2008 and the first quarter of 2009 and the Company's bank lines have been amended to accommodate the heavy spending quarters.

Revenue and Production:

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

Gas sales volumes for the three months ended June 30, 2008 were 39.9 MMcfd, similar to the first quarter of 2008 and 74% higher than the second quarter of 2007. Gas sales volumes were slightly less than anticipated in the second quarter of 2008, primarily as a result of weather related delays in the tie-in of wells drilled in the first quarter of 2008 and plant outages. Gas sales volumes increased 75% from the first half of 2007 as a result of asset acquisitions in 2007 and drilling success.

Oil sales for the three months ended June 30, 2008 averaged 436 bpd compared to 504 bpd in the second quarter of 2007 and 588 bpd in the first quarter of 2008. Oil sales for the six months ended June 30, 2008 were 512 bpd, 5% lower than the first half of 2007. The majority of the Company's oil production is from central and eastern Alberta.

Natural gas liquids sales for the three months ended June 30, 2008 averaged 829 bpd compared to 98 bpd for the second quarter of 2007 and 757 bpd in the first quarter of 2008. Natural gas liquids sales for the six months ended June 30, 2008 averaged 793 bpd compared to 139 bpd for the first half of 2007. Development activity on the liquids rich assets acquired in the September 2007 acquisition contributed to the volume increases.

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



Three months ended Six months ended
June 30 June 30
-------------------- -------------------
Oil and Natural Gas Revenue 2008 2007 2008 2007
(thousands of dollars)

Natural gas $ 37,249 $ 15,125 $ 65,526 $ 30,196
Natural gas hedging gain (loss) - - (1,341) 1,157
Oil 4,580 2,662 9,452 5,429
NGL 6,657 526 12,051 1,311
Royalty and other 535 127 1,028 456
----------------------------------------------------------------------------
Total $ 49,021 $ 18,440 $ 86,716 $ 38,549
----------------------------------------------------------------------------

Production
Natural gas (Mcfd) 39,881 22,928 39,546 22,547
Oil (bpd) 436 504 512 537
NGL (bpd) 829 98 793 139
----------------------------------------------------------------------------
Total (BOED) 7,912 4,423 7,896 4,434
----------------------------------------------------------------------------

Prices
Natural gas ($/Mcf) $ 10.26 $ 7.25 $ 8.92 $ 7.68
Oil ($/bbl) 115.48 58.07 101.50 55.82
NGL ($/bbl) 88.21 58.71 83.48 52.26
Total ($/BOE)(1) $ 68.08 $ 45.81 $ 60.35 $ 48.04

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


Anderson Energy's average gas sales price was $10.26 per Mcf for the three months ended June 30, 2008, 36% higher than the first quarter of 2008 price of $7.55 per Mcf and 42% higher than the second quarter of 2007 price of $7.25 per Mcf. Anderson Energy's average gas sales price was $8.92 per Mcf for the six months ended June 30, 2008, 16% higher than the first half of 2007 price of $7.68 per Mcf. 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 six months ended June 30, 2008 was $9.10 per Mcf before this loss. The increase in prices was the result of stronger natural gas markets.

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

Natural gas prices strengthened in the second quarter of 2008. The AECO 5A daily index increased to $9.68 per GJ for the three months ended June 30, 2008 compared to the 2008 first quarter average of $7.49 per GJ and the 2007 second quarter average of $6.70 per GJ. Anderson Energy sells most of its gas at the daily index less associated transportation.

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

Royalties:

Royalties were 22% of revenue for the three months ended June 30, 2008 compared to 16% for the second quarter of 2007 and 23% for the first quarter of 2008. Royalties were 22% of revenue for the six months ended June 30, 2008 compared to 19% for same period in 2007. Royalties in 2007 were reduced by large 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. The $1.3 million hedging loss in the first quarter of 2008 also impacted the effective royalty rate in the first half of 2008.

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, and approximately 34% of our prospects are on freehold lands. These changes are expected to come into effect on January 1, 2009 and are discussed further under "Business Risks".



Three months ended Six months ended
June 30 June 30
-------------------- ------------------
2008 2007(1) 2008 2007(1)
------ -------- -------- --------
Royalties (%) 22% 16% 22% 19%
Royalties ($/BOE) $ 14.70 $ 7.37 $ 13.41 $ 9.14

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


Operating Expenses:

Operating expenses were $11.32 per BOE for the three months ended June 30, 2008 compared to $10.97 per BOE in the second quarter of 2007 and $12.13 per BOE in the first quarter of 2008. Operating expenses were $11.72 per BOE for the six months ended June 30, 2008 compared to $11.60 per BOE in the first half of 2007. Operating costs were negatively impacted in the first half of 2008 by the higher costs associated with the extremely cold weather that froze equipment and caused plant problems in the first quarter of 2008. Operating costs are expected to decrease on a per BOE basis as the Company becomes less dependent on third party processing. By July 2008, the Company had completed three plant construction projects at Willesden Green, Wilson Creek and Buck Lake. These projects are expected to contribute to a reduction in operating expenses per BOE. These decreases in operating expenses may be offset to some extent by increases in operating expenses associated with testing the Chedderville Leduc A sour gas pool in the second half of the year. This pilot project is expected to have higher than average operating costs.



Operating Netback:

Three months ended Six months ended
June 30 June 30
-------------------- ------------------
2008 2007 2008 2007
(thousands of dollars)
Revenue $ 49,021 $ 18,440 $ 86,716 $ 38,549
Royalties (10,586) (2,967) (19,274) (7,336)
Operating expenses (8,150) (4,417) (16,844) (9,310)
-------------------- ------------------
$ 30,285 $ 11,056 $ 50,598 $ 21,903
-------------------- ------------------

Sales (MBOE) 720.0 402.5 1,437.0 802.5

($/BOE)
Revenue $ 68.08 $ 45.81 $ 60.35 $ 48.04
Royalties (14.70) (7.37) (13.41) (9.14)
Operating expenses (11.32) (10.97) (11.72) (11.60)
-------------------- ------------------
$ 42.06 $ 27.47 $ 35.22 $ 27.30
-------------------- ------------------


General and Administrative Expenses:

General and administrative expenses were $1.8 million or $2.48 per BOE for the three months ended June 30, 2008 compared to $1.7 million or $4.18 per BOE in the second quarter of 2007 and $1.6 million or $2.16 per BOE in the first quarter of 2008. General and administrative expenses were $3.3 million or $2.32 per BOE for the six months ended June 30, 2008 compared to $3.3 million or $4.17 per BOE for the first half 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 second half of 2008 as the Company is hiring additional staff to manage its large upcoming winter drilling program.



Three months ended Six months ended
June 30 June 30
-------------------- -------------------
2008 2007 2008 2007

General and administrative (gross) $ 3,158 $ 2,635 $ 6,078 $ 5,450
Overhead recoveries (331) (302) (867) (729)
Capitalized (1,041) (652) (1,873) (1,372)
-------------------------------------------------------- -------------------
General and administrative (net) $ 1,786 $ 1,681 $ 3,338 $ 3,349
-------------------------------------------------------- -------------------

General and administrative ($/BOE) $ 2.48 $ 4.18 $ 2.32 $ 4.17

% G&A capitalized 33% 25% 31% 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 second quarter of 2008 ($0.2 million net of amounts capitalized) versus $0.2 million ($0.1 million net of amounts capitalized) in the second quarter of 2007. Stock-based compensation costs were $0.8 million for the first half of 2008 ($0.5 million net of amounts capitalized) versus $0.5 million ($0.3 million net of amounts capitalized) in the first half of 2007. The increase is a result of additional stock options being granted to new and existing staff members.

Interest Expense:

Interest expense was $1.2 million for the second quarter of 2008, compared to $1.2 million in the first quarter of 2008 and $0.5 million in the second quarter of the prior year. Interest expense was $2.4 million for the first half of 2008, compared to $1.0 million in the first half of 2007. The increase in interest expense is due to the higher debt levels resulting from the Company's winter drilling program. The Company's front-end loaded capital program resulted in capital expenditures in excess of funds from operations in the first half of 2008. Assets acquired in the second half of 2007 were also partially financed with debt. The average effective interest rate on outstanding bank loans was 5.0% for the three months ended June 30, 2008 compared to 5.8% for the three months ended June 30, 2007 and 5.2% for the six months ended June 30, 2008 compared to 5.7% for the six months ended June 30, 2007.

Depletion and Depreciation:

Depletion and depreciation was $20.15 per BOE for the second quarter of 2008 compared to $20.20 per BOE in the first quarter of 2008 and $21.31 per BOE in the second quarter of 2007. Depletion and depreciation was $20.18 per BOE for the first half of 2008 compared to $21.25 per BOE in the first half of 2007. Depletion and depreciation expense is calculated based on proved reserves only. An increase in proved reserves in 2007 and the first half of 2008 resulted in the decrease in depletion and depreciation expense on a per BOE basis.

Asset Retirement Obligation:

The Company recorded $0.5 million in asset retirement obligations in the second quarter of 2008 and $1.8 million in the first half of 2008. Accretion expense was $0.5 million for the second quarter of 2008 compared to $0.3 million in the second quarter of 2007, and $0.9 million for the first half of 2008 compared to $0.6 million in the first half 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 $282 million in tax pools at June 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 second quarter of 2008 were $27.3 million ($0.31 per share), a 107% increase on a per share basis over the $9.0 million ($0.15 per share) recorded in the same period of the prior year and 55% higher than the $17.6 million ($0.20 per share) recorded in the first quarter of 2008. Funds from operations for the first half of 2008 were $44.9 million ($0.51 per share) compared to $17.6 million ($0.31 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, partially offset by higher expenses. Cash from operating activities also increased year over year for similar reasons.



Three months ended Six months ended
June 30 June 30
----------------------------------------
(thousands of dollars) 2008 2007 2008 2007
----------------------------------------
Cash from operating activities $ 27,660 $ 8,943 $ 45,076 $ 17,348
Changes in non-cash working capital (375) (244) (300) (59)
Asset retirement expenditures 36 273 136 306
----------------------------------------
Funds from operations $ 27,321 $ 8,972 $ 44,912 $ 17,595
----------------------------------------
----------------------------------------


Earnings:

The Company reported earnings of $8.5 million in the second quarter of 2008 compared to $0.4 million for the second quarter of 2007 and earnings of $1.7 million in the first quarter of 2008. The Company reported earnings of $10.2 million in the first half of 2008 compared to $0.3 million in the first half of 2007. Earnings were positively impacted by higher production, higher commodity prices and lower depletion and depreciation on a per BOE basis.

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 $ 6.5 $ 0.07 $ 4.6 $ 0.05
US $5.00/bbl in the WTI crude price $ 1.7 $ 0.02 $ 1.2 $ 0.01
US $0.01 in the U.S./Cdn exchange
rate $ 1.1 $ 0.01 $ 0.8 $ 0.01
1% in short-term interest rate $ 1.1 $ 0.01 $ 0.8 $ 0.01


Capital Expenditures

The Company spent $16.8 million on capital expenditures in the second quarter of 2008 and $52.1 million in the six months ended June 30, 2008. The breakdown of expenditures is shown below:



Three months Six months
ended ended
(thousands of dollars) June 30, 2008 June 30, 2008
------------------------------

Land, geological & geophysical costs $ 173 $ 649
Property acquisitions, net of dispositions (875) (875)
Drilling, completion and recompletion 2,148 24,531
Facilities and well equipment 14,245 25,888
Capitalized G&A 1,001 1,833
------------------------------
Total oil and natural gas expenditures 16,692 52,026
Office equipment and furniture 80 105
------------------------------
Total capital expenditures 16,772 52,131

Non-cash asset retirement obligations and
capitalized stock based compensation 640 2,170
------------------------------
Total cash and non-cash capital additions $ 17,412 $ 54,301
------------------------------
------------------------------


Drilling statistics are shown below:

Three months ended June 30 Six months ended June 30
----------------------------------------------------------
2008 2007 2008 2007
Gross Net Gross Net Gross Net Gross Net

Gas 1.0 0.2 5.0 4.4 76.0 54.0 40.0 25.7
Oil - - - - 4.0 0.9 3.0 1.5
Dry - - - - 7.0 6.1 5.0 2.2
----------------------------------------------------------
Total 1.0 0.2 5.0 4.4 87.0 61.0 48.0 29.4
----------------------------------------------------------

Success rate (%) 100% 100% 100% 100% 92% 90% 90% 93%


During the second quarter of 2008, the Company participated in the drilling of only one gross (0.2 net) well which was successful. The Company spent $14.2 million on facilities, completing three natural gas plant/compressor station projects at Buck Lake, Willesden Green and Wilson Creek. These projects were all constructed at a 100% working interest.

Share Information

The Company's shares have been listed on the Toronto Stock Exchange since September 7, 2005 under the symbol "AXL". As of August 12, 2008, there were 87.3 million common shares outstanding and 6.6 million stock options outstanding. The Company's market capitalization at August 12, 2008 was $279.4 million.



Three Months Ended June 30 Six Months Ended June 30
Share Price on TSX 2008 2007 2008 2007

High $ 5.39 $ 5.40 $ 5.39 $ 5.40
Low $ 3.38 $ 4.28 $ 2.44 $ 3.35
Close $ 5.37 $ 4.60 $ 5.37 $ 4.60
Volume 29,082,974 11,515,777 53,041,297 16,935,354

Shares
outstanding at
June 30 87,300,401 61,594,401 87,300,401 61,594,401
Market
capitalization at
June 30 $468,803,153 $283,334,245 $468,803,153 $283,334,245


Liquidity and Capital Resources

At June 30, 2008, the Company had outstanding bank loans of $81.2 million and a working capital deficiency of $23.0 million. The large working capital deficiency is due to accruals associated with the capital program.

Due to the expansion of the Edmonton Sands winter drilling program, the Company has increased its capital budget for 2008 to $117.0 million, net of dispositions of $0.8 million. Most of the capital expansion is to be spent in the fourth quarter of 2008. Anderson Energy will continue to review its capital budget throughout the remainder of the year and adjust it accordingly and prudently to accommodate changes in the outlook for natural gas prices.

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 June 30, 2008, the Company had a $95.0 million extendible revolving term credit facility, a $10.0 million working capital credit facility and a $25.0 million supplemental credit facility with a syndicate of Canadian banks. On August 8, 2008, the Company received approval from its lenders to increase its extendible, revolving term credit facility by $15.0 million to $110.0 million. The working capital facility remains at $10.0 million. The supplemental facility, which was originally scheduled to reduce to $10.0 million on September 30, 2008 and expire on December 31, 2008, has been extended to June 30, 2009 at $10.0 million. The amendments are subject to completion of customary loan and security documentation. The bank facilities were modified to accommodate a 200 well Edmonton Sands drilling program in the upcoming winter. 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 budget through a combination of cash flow, debt and asset sales. Anderson Energy anticipates that it will make use of equity financing for any significant expansion in its capital program or to finance any significant acquisitions.

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 $0.9 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 million cubic feet per day of gas sales for various terms expiring between 2008 and 2015.

In the second quarter of 2008, the Company signed letters of intent to sell various non-core assets. The Company completed the sale of $0.8 million of assets in the second quarter of 2008, but was unable to close the sale of an additional $6.7 million of assets. The Company is continuing to market these non-core assets.

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 has stated that it plans to issue an exposure draft 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 potentially 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 six months ended June 30, 2008.

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.

In the first quarter of 2008, Anderson Energy has made a significant Edmonton Sands discovery in the Bigoray area. This discovery has extended the previously mapped limits of the Company's Edmonton Sands project from 2,200 to 4,600 sections.

Anderson Energy currently plans to drill 246 gross (165 net) wells in 2008, with the Edmonton Sands project representing 90% of the net drilling program. The revised 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 has brought these facilities on stream near the end of the second quarter, which should help to reduce 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 remains unchanged at 8,200 to 8,600 BOED of production as the additional capital to be spent is heavily weighted to the fourth quarter. Expected 2008 production is a 54% to 61% increase over 2007 production. Risks associated with this guidance include gas plant capacity, regulatory issues, weather problems and access to industry 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 half of 2008. Product prices have improved significantly since the third quarter of 2007, which has had a significant impact on funds from operations and earnings in the most recent quarter.



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


Q2 2008 Q1 2008 Q4 2007 Q3 2007
----------------------------------------------

Oil and gas revenue before
royalties $ 49,021 $ 37,695 $ 27,775 $ 17,261
Funds from operations $ 27,321 $ 17,591 $ 12,564 $ 6,255
Funds from operations per
share
Basic $ 0.31 $ 0.20 $ 0.14 $ 0.09
Diluted $ 0.31 $ 0.20 $ 0.14 $ 0.09
Earnings (loss) $ 8,509 $ 1,696 $ 4,867 $ (3,018)
Earning (loss) per share
Basic $ 0.10 $ 0.02 $ 0.06 $ (0.04)
Diluted $ 0.10 $ 0.02 $ 0.06 $ (0.04)
Capital expenditures,
including acquisitions
net of dispositions $ 16,772 $ 35,359 $ 30,300 $ 135,966
Cash from operating
activities $ 27,660 $ 17,416 $ 11,110 $ 5,801
Daily sales
Natural gas (Mcfd) 39,881 39,210 35,672 26,860
Liquids (bpd) 1,265 1,345 1,150 843
BOE (bpd) 7,912 7,879 7,095 5,320
Average prices
Natural gas ($/Mcf) $ 10.26 $ 7.55 $ 6.09 $ 5.00
Liquids ($/bbl) $ 97.61 $ 83.91 $ 72.28 $ 63.31
BOE ($/BOE) $ 68.08 $ 52.57 $ 42.55 $ 35.27


Q2 2007 Q1 2007 Q4 2006 Q3 2006
----------------------------------------------

Oil and gas revenue before
royalties $ 18,440 $ 20,109 $ 16,820 $ 14,651
Funds from operations $ 8,972 $ 8,623 $ 7,996 $ 5,873
Funds from operations per
share
Basic $ 0.15 $ 0.16 $ 0.15 $ 0.12
Diluted $ 0.15 $ 0.16 $ 0.15 $ 0.12
Earnings (loss) $ 368 $ (33) $ 846 $ (1,509)
Earning (loss) per share
Basic $ 0.01 $ - $ 0.02 $ (0.03)
Diluted $ 0.01 $ - $ 0.02 $ (0.03)
Capital expenditures,
including acquisitions
net of dispositions $ 17,586 $ 27,281 $ 20,662 $ 10,948
Cash from operating
activities $ 8,943 $ 8,405 $ 8,651 $ 5,872
Daily sales
Natural gas (Mcfd) 22,928 22,162 21,075 19,621
Liquids (bpd) 602 750 692 736
BOE (bpd) 4,423 4,444 4,205 4,006
Average prices
Natural gas ($/Mcf) $ 7.25 $ 8.14 $ 6.82 $ 5.71
Liquids ($/bbl) $ 58.18 $ 52.59 $ 51.09 $ 62.14
BOE ($/BOE) $ 45.81 $ 50.28 $ 43.48 $ 39.75


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)

----------------------------------------------------------------------------
----------------------------------------------------------------------------
June 30, December 31,
2008 2007
----------------------------------------------------------------------------

Assets

Current assets:
Cash $ 118 $ 2
Accounts receivable and accruals 31,744 31,540
Prepaid expenses and deposits 2,925 2,522
----------------------------------------------------------------------------
34,787 34,064

Property, plant and equipment (note 2) 487,329 461,896

Goodwill 35,364 35,364
----------------------------------------------------------------------------
$ 557,480 $ 531,324
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities and Shareholders' Equity

Current liabilities:
Accounts payable and accruals $ 57,786 $ 62,915

Bank loans (note 3) 81,163 67,981

Asset retirement obligations (note 4) 27,119 24,526

Future income taxes 45,911 41,450
----------------------------------------------------------------------------
211,979 196,872

Shareholders' equity:
Share capital (note 5) 334,176 334,147
Contributed surplus (note 5) 2,820 2,005
Retained earnings (deficit) 8,505 (1,700)
----------------------------------------------------------------------------
345,501 334,452

----------------------------------------------------------------------------
$ 557,480 $ 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 Six months ended
June 30, June 30,
2008 2007 2008 2007
----------------------------------------------------------------------------

Revenues
Oil and gas sales $ 49,021 $ 18,440 $ 86,716 $ 38,549
Royalties (10,586) (2,967) (19,274) (7,336)
Interest income 13 59 45 61
----------------------------------------------------------------------------
38,448 15,532 67,487 31,274

Expenses
Operating 8,150 4,417 16,844 9,310
General and administrative 1,786 1,681 3,338 3,349
Stock-based compensation 227 127 460 258
Interest and other financing
charges 1,191 462 2,393 1,020
Depletion, depreciation and
accretion 14,985 8,877 29,912 17,622
----------------------------------------------------------------------------
26,339 15,564 52,947 31,559
----------------------------------------------------------------------------
Earnings (loss) before taxes 12,109 (32) 14,540 (285)

Future income taxes (reduction) 3,600 (400) 4,335 (620)
----------------------------------------------------------------------------
Earnings for the period 8,509 368 10,205 335

Reclassification of accumulated
other comprehensive income to
earnings - - - (1,465)

----------------------------------------------------------------------------
Comprehensive income (loss) $ 8,509 $ 368 $ 10,205 $ (1,130)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Deficit, beginning of period $ (4) $ (3,917) $ (1,700) $ (3,884)
Earnings for the period 8,509 368 10,205 335
----------------------------------------------------------------------------
Retained earnings (deficit),
end of period $ 8,505 $ (3,549) $ 8,505 $ (3,549)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Earnings per share (note 5)
Basic $ 0.10 $ 0.01 $ 0.12 $ 0.01
Diluted $ 0.10 $ 0.01 $ 0.12 $ 0.01
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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 Six months ended
June 30, June 30,
2008 2007 2008 2007
----------------------------------------------------------------------------

Cash provided by (used in):

Operations
Earnings for the period $ 8,509 $ 368 $ 10,205 $ 335
Items not involving cash
Depletion, depreciation
and accretion 14,985 8,877 29,912 17,622
Future income tax taxes
(reduction) 3,600 (400) 4,335 (620)
Stock-based compensation 227 127 460 258
Asset retirement expenditures (36) (273) (136) (306)
Changes in non-cash working
capital
Accounts receivable and accruals (2,754) (1,438) (7,579) (1,355)
Prepaid expenses and deposits (375) 164 (523) 13
Accounts payable and accruals 3,504 1,518 8,402 1,401
----------------------------------------------------------------------------
27,660 8,943 45,076 17,348

Financing
Increase (decrease) in
bank loans (6,741) (16,815) 13,182 (891)
Issue of common shares 25 32,563 25 32,563
----------------------------------------------------------------------------
(6,716) 15,748 13,207 31,672

Investments
Additions to property, plant
and equipment (17,647) (17,649) (53,006) (45,673)
Proceeds on disposition of
properties 875 63 875 806
Changes in non-cash working
capital
Accounts receivable and accruals 3,845 2,735 7,375 4,883
Prepaid expenses and deposits 463 4 120 (98)
Accounts payable and accruals (8,365) (9,837) (13,531) (8,939)
----------------------------------------------------------------------------
(20,829) (24,684) (58,167) (49,021)
----------------------------------------------------------------------------
Increase (decrease) in cash 115 7 116 (1)

Cash, beginning of period 3 3 2 11
----------------------------------------------------------------------------

Cash, end of period $ 118 $ 10 $ 118 $ 10
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.


ANDERSON ENERGY LTD.
Notes to the Consolidated Financial Statements
Three and Six months ended June 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 has stated that it plans to issue an exposure draft 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 potentially 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

----------------------------------------------------------------------------
----------------------------------------------------------------------------
June 30, December 31,
2008 2007
----------------------------------------------------------------------------
Cost $ 627,429 $ 573,002
Less accumulated depletion and depreciation (140,100) (111,106)
----------------------------------------------------------------------------
Net book value $ 487,329 $ 461,896
----------------------------------------------------------------------------
----------------------------------------------------------------------------


At June 30, 2008, unproved property costs of $16.6 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 $168.0 million (December 31, 2007 - $177.8 million) have been included in the depletion and depreciation calculation.

For the six months ended June 30, 2008, $2.2 million (June 30, 2007 - $1.6 million) of general and administrative costs including $0.4 million (June 30, 2007 - $0.2 million) of stock-based compensation costs were capitalized. The future tax liability of $126,000 (June 30, 2007 - $97,000) associated with the capitalized stock-based compensation has also been capitalized. For the three months ended June 30, 2008, $1.2 million (June 30, 2007 - $0.8 million) of general and administrative costs including $0.2 million (June 30, 2007 - $0.1 million) of stock-based compensation costs were capitalized. Capitalized general and administrative costs consist of salaries and associated office rent of staff involved in capital activities.

No impairment was recognized under the ceiling test at June 30, 2008. The future commodity prices used in the ceiling test were based on commodity price forecasts of the Company's independent reserve engineers adjusted for differentials specific to the Company's reserves.

3. Bank loans

The Company has a $95 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. Advances under the Facilities can be drawn in either Canadian or U.S. funds. The Facilities 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 June 30, 2008, there were no advances in U.S. funds. The average effective interest rate on advances in 2008 was 5.2% (June 30, 2007 - 5.7%).

On January 17, 2008, the Company entered into a $25 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 reduces to $10 million on September 30, 2008, and shall be repaid in full on or before December 31, 2008. Advances under the 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 June 30, 2008 there were no advances under the Supplemental Facility.

On August 8, 2008, the Company received approval from its lenders to increase the extendible, revolving term credit facility by $15 million to $110 million. The Supplemental Facility will become $10 million and will be extended to June 30, 2009 when it will be required to be repaid in full. The working capital credit facility will remain unchanged at $10 million. The total bank facilities are $130 million. The amendments are subject to completion of customary loan and security documentation.

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 $57.8 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:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
June 30, December 31,
2008 2007
----------------------------------------------------------------------------
Balance, beginning of period $ 24,526 $ 14,905
Liabilities incurred during period 1,811 3,060
Liabilities assumed on corporate acquisition - 5,923
Liabilities settled in period (136) (742)
Accretion expense 918 1,380
----------------------------------------------------------------------------
Balance, end of period $ 27,119 $ 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 June 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 six months ended June 30, 2008 and year ended December 31, 2007 are as follows:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Number of Weighted average
options exercise 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 337,900 4.48
Exercised (6,000) 4.13
Expirations and forfeitures (62,250) 4.35
----------------------------------------------------------------------------
Balance at June 30, 2008 6,566,956 $ 4.64
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Exercisable at June 30, 2008 3,812,639 $ 4.74
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

$3.61 to $5.00 5,304,356 $ 4.03 4.0 2,939,506 $ 4.01
$5.01 to $7.50 537,200 6.17 2.9 379,200 6.16
$7.51 to $9.01 725,400 8.01 2.3 493,933 8.01
----------------------------------------------------------
Total at
June 30, 2008 6,566,956 $ 4.64 3.8 3,812,639 $ 4.74
----------------------------------------------------------
----------------------------------------------------------


The fair value of the options issued during the period ended June 30, 2008 ranged between $1.57 to $2.13 per option. (June 30, 2007 - $1.77 to $1.99 per option). The weighted average assumptions used in arriving at the values were: a risk-free interest rate of 3.2% (June 30, 2007 - 4.0%), expected option life of five years, expected volatility of 45% (June 30, 2007 - 50%) and a dividend yield of 0%.

Per share amounts

During the six months ended June 30, 2008 there were 87,295,687 weighted average shares outstanding (June 30, 2007 - 56,631,257). On a diluted basis, there were 87,602,769 weighted average shares outstanding (June 30, 2007 - 57,103,674) after giving effect to dilutive stock options. During the three months ended June 30, 2008 there were 87,296,972 weighted average shares outstanding (June 30, 2007 - 59,588,258). On a diluted basis, there were 87,603,995 weighted average shares outstanding (June 30, 2007 - 60,059,158) after giving effect to dilutive stock options. At June 30, 2008, there were 3,930,300 options that were anti-dilutive (June 30, 2007 - 2,129,300).



Contributed surplus

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Amount
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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 819
Transferred from contributed surplus on stock option exercise (4)
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Balance at June 30, 2008 $ 2,820
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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 considers its capital structure to include shareholders' equity, bank loans and working capital. In order to maintain or adjust the capital structure, the Company may from time to time issue shares, seek additional debt financing and adjust its capital spending to manage current and projected debt levels.

Consistent with other companies in the oil and gas sector, Anderson Energy monitors capital based on the ratio of total debt to funds from operations. This ratio is calculated by dividing total debt at the end of the period (comprised of the working capital deficiency and outstanding 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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June 30, December 31,
2008 2007
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Bank loans $ 81,163 $ 67,981
Current liabilities 57,786 62,915
Current assets (34,787) (34,064)
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Total debt $ 104,162 $ 96,832
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Cash from operating activities in quarter $ 27,660 $ 11,110
Changes in non-cash working capital (375) 1,404
Asset retirement expenditures 36 50
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Funds from operations in quarter $ 27,321 $ 12,564
Annualized current quarter funds from
operations $ 109,284 $ 50,256
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Total debt to funds from operations 1.0 1.9
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At June 30, 2008, the Company's total debt to annualized funds from operations was 1.0 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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June 30, June 30,
2008 2007
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Interest paid $ 1,940 $ 886
Interest received (49) (67)
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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 June 30, 2008, the maximum credit exposure is the carrying amount of the accounts receivable and accruals of $31.7 million (December 31, 2007 - $31.5 million). As at June 30, 2008, the Company's receivables consisted of $12.3 million from joint venture partners and other trade receivables and $19.4 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 $19.4 million of revenue accruals and receivables from petroleum and natural gas marketers, $16.3 million was received on or about July 25, 2008.

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 June 30, 2008, the largest amount owing from one partner is $1.9 million.

The Company is 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 June 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 June 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 June 30, 2008 the Company considers it receivables to be aged as
follows:

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Aging June 30, 2008
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Not past due $ 26,743
Past due by less than 120 days 658
Past due by more than 120 days 4,343
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Total $ 31,744
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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 June 30, 2008:



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Financial Liabilities less than
1 Year 1-2 Years
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Accounts payable and accrued liabilities $ 57,786 $ -
Bank debt - principal - 81,163
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Total $ 57,786 $ 81,163
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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 June 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 June 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 six months ended June 30, 2007 were $1.2 million and were included in oil and gas sales.

There were no commodity price risk contracts outstanding at June 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 six months ended June 30, 2008, if interest rates had been 1% lower with all other variables held constant, earnings for the period would have been $260,000 (June 30, 2007 - $102,000) higher, due to lower interest expense. An equal and opposite impact would have occurred had interest rates been higher by the same amounts.

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



Corporate Information Contact Information

Head Office Anderson Energy Ltd.
700 Selkirk House Brian H. Dau
555 4(th) 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
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