Anderson Energy Ltd.
TSX : AXL

Anderson Energy Ltd.

May 14, 2008 09:00 ET

Anderson Energy Ltd. Announces 2008 First Quarter Results

CALGARY, ALBERTA--(Marketwire - May 14, 2008) - Anderson Energy Ltd. ("Anderson Energy" or the "Company") (TSX:AXL) is pleased to announce its operating and financial results for the first quarter ended March 31, 2008.

Highlights

- First quarter production averaged 7,879 BOED, an 11% increase over the fourth quarter of 2007 and a 77% increase over the first quarter of 2007. Current production is 8,500 BOED with behind pipe production capability of an additional 900 BOED.

- Funds from operations were $17.6 million, or $0.20 per share, 40% higher than the fourth quarter of 2007 and 104% higher than the first quarter of 2007.

- The Company completed its largest and most successful quarterly drilling program in its history with 86 gross (60.8 net) wells drilled with a success rate of 90%. During the quarter, the Company drilled 71 gross (56.0 net) Edmonton Sands wells.

- Three 100% Mannville wells drilled in the quarter are currently producing approximately 450 BOED.

- The Company's future drilling inventory is 1,128 gross (570 net) wells as of March 31, 2008, based on four well per section Edmonton Sands drilling density.

- The Company 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 sections to 4,600 sections. The Company now estimates that there is 5.2 Tcf of prospective resource in the Edmonton Sands fairway with cumulative production to December 31, 2007 of 0.2 Tcf. The Company owns or controls 318 gross (191 net) sections of Edmonton Sands prospective land in this fairway.

- The 2008 capital budget has been increased from $60 million to $85 million based on current and forecasted natural gas prices. The increase in capital spending is expected to be funded out of cash flow and existing bank lines and to occur largely in the fourth quarter of the year.



Financial and Operating Highlights
Three months ended
March 31
----------------------
2008 2007 % Change
Financial
(thousands of dollars, except share data)

Total oil and gas revenue $ 37,695 $ 20,109 87%

Funds from operations $ 17,591 $ 8,623 104%
Per common share - basic $ 0.20 $ 0.16 25%
- diluted $ 0.20 $ 0.16 25%

Earnings (loss) $ 1,696 $ (33) 5239%
Per common share - basic $ 0.02 $ -
- diluted $ 0.02 $ -

Field capital expenditures $ 35,359 $ 28,024 26%
Acquisitions, net of dispositions $ - $ (743) 100%
Debt, net of working capital $ 114,700 $ 67,344 70%

Shareholders' equity $ 336,553 $ 201,684 67%

Average shares outstanding (thousands)
Basic 87,294 53,641 63%
Diluted 87,294 53,641 63%

Ending shares outstanding (thousands) 87,294 53,641 63%

Operating (6 Mcf:1bbl conversion)

Average daily sales
Natural gas (Mcfd) 39,210 22,162 77%
Light/medium crude oil (bpd) 588 571 3%
NGL (bpd) 757 179 323%
Barrels of oil equivalent (BOED) 7,879 4,444 77%

Average sales price
Natural gas ($/Mcf) 7.55 8.14 (7%)
Light/medium crude oil ($/bbl) 91.13 53.82 69%
NGL ($/bbl) 78.30 48.69 61%
Barrels of oil equivalent ($/BOE) 52.57 50.27 5%

Royalties ($/BOE) 12.12 10.92 11%
Operating costs ($/BOE) 12.13 12.23 (1%)
Operating netbacks ($/BOE) 28.32 27.12 4%
General and administrative ($/BOE) 2.16 4.17 (48%)

Wells drilled (gross) 86 43 100%


Operating Highlights

Production:

In the first quarter of 2008, production averaged 7,879 BOED, an increase of 77% over the first quarter of 2007 and 11% over the fourth quarter of 2007. The Company tied in 17 net wells for production in the quarter. Current production is 8,500 BOED, with behind pipe production capability of 900 BOED. The Company is proceeding to tie in 23 wells in May.

The Company's funds from operations were $17.6 million and earnings were $1.7 million. This compares to funds from operations of $8.6 million and a loss of $33,000 in the first quarter of 2007. The natural gas price received in the quarter was $7.55 per Mcf (net of a $1.3 million hedging loss) compared to $8.14 per Mcf in the first quarter of 2007 (including a $1.2 million hedging gain). Since the end of the quarter, natural gas prices have increased to over $9.00 per Mcf. Crude oil and natural gas liquids prices were substantially stronger in the first quarter with an average price of $83.91 per bbl in the first quarter of 2008 compared to $52.59 per bbl in the first quarter of 2007. The Company's operating netback was $28.32 per bbl in the first quarter of 2008 compared to $27.12 per bbl in the first quarter of 2007, primarily due to stronger liquids pricing and more liquids production.

Capital Program:

Capital expenditures were $35.4 million during the quarter, of which $22.4 million was spent on drilling and completion operations, $11.6 million was spent on facilities and $0.5 million was spent on land acquisitions.

During the first quarter of 2008, the Company drilled 86 gross (60.8 net) wells with a success rate of 90%, of which 71 gross (56.0 net) were Edmonton Sands wells. The Company drilled its first six well per section Edmonton Sands development with both the fifth and sixth wells exhibiting virgin pressure. Additional holding applications for more than four wells per section are being prepared for regulatory approval.

The Company drilled three 100% working interest Mannville gas wells in the first quarter of 2008. These wells are now on-stream and producing 450 BOED. Third party operated Horseshoe Canyon Coal Bed Methane ("CBM") drilling resulted in 8 gross (1 net) gas wells. Third party operated oil drilling resulted in 4 gross (0.9 net) wells drilled.

The Company 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 sections to 4,600 sections. The Company now estimates that there are 5.2 Tcf of prospective resource in the Edmonton Sands fairway with cumulative production to December 31, 2007 of 0.2 Tcf. The Company owns or controls 318 gross (191 net) sections of Edmonton Sands prospective land in this fairway and continues to add to this inventory.

In 2007, with the reduced drilling levels in western Canada, we started to see a reduction in the cost of doing business. The Company does most of its engineering design work with in-house employees and was able to engineer permanent cost savings through a redesign of the Edmonton Sands drilling and completion operations. The average cost to drill and complete an Edmonton Sands gas well in 2007 was $352,000, compared to $454,000 per well two years ago. In the first quarter of 2008, drilling and completion costs were approximately $285,000 per well, a 19% reduction, achieved primarily through engineering design changes rather than lower service company costs as illustrated by the fact that the day rate for drilling rigs in the first quarter of 2008 was only 2% lower than in 2007. As a result, the cost savings are less likely to be eroded by changes in activity levels in the industry. The impact of the cost savings achieved in the first quarter of 2008 were not incorporated into future development costs used in the 2007 reserve report, but potentially could be in 2008.

During the first quarter of 2008, the Company initiated construction of three new gas plant projects at Willesden Green, Wilson Creek and Buck Lake. Equipment has been purchased and installation is scheduled to commence in the second quarter. All three projects are estimated to be on-stream early in the third quarter of 2008. These projects are expected to contribute to a reduction in operating costs in the second half of the year. At Willesden Green, the Company will have to shut-in existing production of approximately 500 BOED during the month of June to expand the existing facilities.

Dispositions:

In the second quarter of 2008, the Company completed the sale of $0.8 million in non-core assets. The Company also signed a letter of intent to sell an additional $6.7 million in non-core assets. Closing is expected to occur in July and is subject to the execution of a definitive purchase and sale agreement and other normal closing conditions.

Outlook:

On January 11, 2008, the Company announced a preliminary budget of $60 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 has elected to increase its budget to $85 million. Additional capital has been allocated to additional Edmonton Sands, Mannville and Rock Creek drilling in the fourth quarter of this year. If natural gas prices remain strong, the Company could prudently spend as much as $100 million in the year by pursuing a larger drilling program in the fourth quarter of the year.

The Company drilled three of its Mannville gas prospects in the first quarter and expects to drill eight gross (six net) locations in the balance of the year on its central Alberta Mannville prospects. The Company is planning to drill four 100% working interest Rock Creek infill wells in Westpem in the fourth quarter. There are an additional eight high working interest wells to drill on these lands in 2009. In the third quarter, the Company will be initiating a test to restart the Cheddarville Leduc A gas pool. If this test is successful, this field could be commercially brought back on production in 2009. These prospects were generated from the lands acquired last year in the September 2007 acquisition.

With the cost savings achieved in the recent Edmonton Sands winter drilling program, the Company is now in the planning phase to increase the size of next winter's drilling program by 100% to drill 200 locations from November 2008 to March 2009. The Company is planning to drill additional six well per section developments next winter.

As of March 31, 2008, the Company has identified 1,128 gross (570 net) drilling locations of which 86% are net Edmonton Sands locations and 7.5% 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. Net of locations drilled, the Company increased its drilling inventory in the first quarter by 53 gross (46 net) locations, primarily in the Edmonton Sands area. 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 will be a significant increase to 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 regimes. Therefore, the introduction of the new Alberta royalty regime 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. At December 31, 2007, this land inventory was 303 gross (179 net) sections. As of May 1, 2008, it has grown to 318 gross (191 net) sections.

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 be reviewing its spending plans when it reviews the outlook for natural gas prices this summer. The Company will also be carefully examining potential property and corporate acquisitions in 2008.

The outlook for natural gas has improved substantially in the last few months. The United States natural gas storage is 16.5% less than the previous year and 0.8% lower than the five year average. The changes in natural gas storage and higher crude oil prices have driven the NYMEX natural gas futures market to prices in the US$11.00 per MMBtu range for this summer and US$12.00 per MMBtu for next winter.

We invite our shareholders to attend the Company's third annual meeting as a public company on May 14, 2008 at the Metropolitan Centre in Calgary at 2:00 pm MDT.

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

May 13, 2008

Management's Discussion and Analysis

For the Three Months Ended March 31, 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 months ended March 31, 2008 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 May 13, 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 March 31, 2008 averaged 7,879 BOED, 11% higher than the fourth quarter of 2007. The Company tied in 17 net wells for production during the first quarter of 2008. Higher production, combined with stronger natural gas and crude oil prices increased funds from operations for the three months ended March 31, 2008 to $17.6 million, 40% higher than the fourth quarter of 2007.

Capital expenditures were $35.4 million for the three months ended March 31, 2008. During the first quarter of 2008, the Company drilled 86 gross (60.8 net) wells with a success rate of 90%.

Debt, net of working capital, was $114.7 million at March 31, 2008, higher than at December 31, 2007 as a result of capital expenditures during the quarter being in excess of funds from operations. The 2008 capital budget was heavily weighted to the first quarter of the year and, as a result, early in the first quarter, the Company entered into a one year supplemental credit facility for $25.0 million in addition to its existing bank lines of $105.0 million.

Revenue and Production:

Gas sales comprised 83% of Anderson Energy's total oil and gas sales volumes for the three months ended March 31, 2008, consistent with the fourth quarter of 2007.

Gas sales volumes for the three months ended March 31, 2008 increased 10% to 39.2 MMcfd from 35.7 MMcfd in the fourth quarter of 2007. The increase is a result of realizing a full quarter of production from the 37 wells that were tied in during the last six weeks of 2007. Gas sales volumes increased 77% from the first quarter of 2007 as a result of drilling success and asset acquisitions in 2007. Gas sales volumes were less than anticipated in the quarter as a result well tie in delays and some start-up issues at a new well in Westpem, as well as extremely cold weather that froze equipment and caused plant operating problems.

Oil sales for the three months ended March 31, 2008 averaged 588 bpd compared to 571 bpd for the first quarter of 2007 and 602 bpd in the fourth quarter 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 March 31, 2008 averaged 757 bpd compared to 179 bpd for the first quarter of 2007 and 548 bpd in the fourth quarter 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 period ended March 31, 2008 and 2007.



Three months ended March 31
--------------------------------
2008 2007
----------- -----------

Oil and Natural Gas Revenue
(thousands of dollars)
Natural gas $ 28,278 $ 15,071
Natural gas hedging gain (loss) (1,341) 1,157
Oil 4,872 2,767
NGL 5,393 785
Royalty and other 493 329
----------- -----------
Total $ 37,695 $ 20,109
----------- -----------
----------- -----------


Three months ended March 31
--------------------------------
2008 2007
----------- -----------
Production
Natural gas (Mcfd) 39,210 22,162
Oil (bpd) 588 571
NGL (bpd) 757 179
----------- -----------
Total (BOED) 7,879 4,444
----------- -----------
----------- -----------


Three months ended March 31
--------------------------------
2008 2007
----------- -----------
Prices
Natural gas ($/Mcf) $ 7.55 $ 8.14
Oil ($/bbl) 91.13 53.82
NGL ($/bbl) 78.30 48.69
Total ($/BOE) (i) 52.57 50.27

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


Anderson Energy's average gas sales price was $7.55 per Mcf for the three months ended March 31, 2008, 24% higher than the fourth quarter 2007 price of $6.09 per mcf and 7% lower than the first quarter of 2007 price of $8.14. 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 opportunity loss in sales. The average gas price for the three months ended March 31, 2008 was $7.93 per Mcf before this loss.

There were no physical or financial hedging contracts outstanding as at March 31, 2008.

In the first quarter of 2008, natural gas prices strengthened as storage levels improved. The AECO 5A daily index increased to $7.49 per GJ for the three months ended March 31, 2008 compared to the 2007 fourth quarter average of $5.82 per GJ and the first quarter 2007 average of $7.00 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 25 MMcfd of natural gas sales for various terms ranging from one to eight years.

Royalties:

Royalties were 23% of revenue for the three months ended March 31, 2008 compared to 22% for the three months ended March 31, 2007 and 19% for the fourth quarter of 2007. Royalty rates increased 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 quarter. Royalties were 22% of revenue in the quarter before the hedging loss.

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 March 31
-----------------------------
2008 2007
-------- --------

Royalties (%) 23% 22%
Royalties ($/BOE) $ 12.12 $ 10.92


Operating Expenses:

Operating expenses were $12.13 per BOE for the three months ended March 31, 2008 compared to $12.23 per BOE in the first quarter of 2007 and $11.71 per BOE in the last quarter of 2007. Operating costs were negatively impacted in the first quarter of 2008 by the higher costs associated with the extremely cold weather that froze equipment and caused plant problems. Operating costs are expected to decrease on a per BOE basis in 2008 as the Company becomes less dependent on third party processing. The Company has initiated three large plant construction projects in the first quarter of 2008 at Willesden Green, Wilson Creek and Buck Lake. These projects are expected to be completed in the second half of the year and it is anticipated that once completed, they will contribute to a reduction in operating expenses per BOE in the second half of the year. The Company has entered into agreements to sell non-core assets in the second and third quarters of 2008 which are expected to further reduce operating costs on a per BOE basis.



Operating Netback:
Three months ended March 31
-----------------------------
2008 2007
--------- ---------
(thousands of dollars)

Revenue $ 37,695 $ 20,109
Royalties (8,688) (4,369)
Operating expenses (8,694) (4,893)
--------- ---------
$ 20,313 $ 10,847
--------- ---------
--------- ---------

Sales (MBOE) 717.0 400.0
--------- ---------
--------- ---------
Per BOE
Revenue $ 52.57 $ 50.27
Royalties (12.12) (10.92)
Operating expenses (12.13) (12.23)
--------- ---------
$ 28.32 $ 27.12
--------- ---------
--------- ---------


General and Administrative Expenses:

General and administrative expenses were $1.6 million or $2.16 per BOE for the three months ended March 31, 2008 compared to $1.7 million or $4.17 per BOE for the three months ended March 31, 2007 and $1.4 million or $2.13 per BOE in the fourth quarter of 2007. General and administrative costs on a per BOE basis decreased from the same period in the prior year as a result of increased production.



Three months ended March 31
-----------------------------
(thousands of dollars) 2008 2007
--------- ---------

General and administrative (gross) $ 2,920 $ 2,815
Overhead recovery (536) (427)
Capitalized (832) (720)
--------- ---------
General and administrative (net) $ 1,552 $ 1,668
--------- ---------
--------- ---------
General and administrative ($/BOE) $ 2.16 $ 4.17
% Capitalized 28% 26%


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 first quarter of 2008 ($0.2 million net of amounts capitalized) versus $0.2 million ($0.1 million net of amounts capitalized) in 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 first quarter of 2008, compared to $1.0 million in the fourth quarter of 2007 and $0.6 million in the first quarter of the prior year. 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 quarter. Assets acquired in the second half of 2007 were also partially financed with debt. The average effective interest rate on outstanding bank loans was 5.7% for the three months ended March 31, 2008 compared to 5.6% for the three months ended March 31, 2007.

Depletion and Depreciation:

Depletion and depreciation was $20.20 per BOE for the first quarter of 2008 compared to $20.76 per BOE in the fourth quarter of 2007 and $21.19 per BOE in the first quarter of 2007. Depletion and depreciation expense is calculated based on proved reserves only. An increase in proved reserves in 2007 and the first quarter of 2008 resulted in the decrease in depletion and depreciation expense on a per BOE basis.

Asset Retirement Obligation:

As a result of new drilling, the Company recorded $1.4 million in asset retirement obligations in the first quarter of 2008. Accretion expense was $0.4 million for the first quarter of 2008 compared to $0.3 million in the first quarter of 2007 and was included in depletion and depreciation expense. Accretion expense increased due to new drills and acquisitions.

Income Taxes:

Anderson Energy is not currently taxable. The Company has approximately $293 million in tax pools at March 31, 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 first quarter of 2007 were $17.6 million ($0.20 per share), a 104% increase over the $8.6 million ($0.16 per share) recorded in the same period of the prior year and 40% higher than the $12.6 million ($0.14 per share) recorded in the fourth quarter of 2007. The increase in funds from operations is a result of higher production and higher liquids prices, partially offset by higher expenses. Cash from operating activities also increased year over year for similar reasons.



Three months ended March 31
-----------------------------
(thousands of dollars) 2008 2007
--------- ---------
Cash from operating activities $ 17,416 $ 8,405
Changes in non-cash working capital 75 185
Asset retirement obligations 100 33
--------- ---------
Funds from operations $ 17,591 $ 8,623
--------- ---------
--------- ---------


Earnings:

The Company reported earnings of $1.7 million in the first quarter of 2008 compared to a loss of $33,000 for the first quarter of 2007 and earnings of $4.9 million for the three months ended December 31, 2007. Earnings in the first quarter of 2008 were positively impacted by higher production, higher liquids prices and lower depletion and depreciation on a per BOE basis. Earnings in the fourth quarter of 2007 were positively impacted by income tax rate reductions.

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 $35.4 million on capital expenditures in the first quarter of 2008. The breakdown of expenditures is shown below:



Three months ended March 31
-----------------------------
(thousands of dollars) 2008 2007
--------- ---------

Land, geological & geophysical costs $ 476 $ 1,722
Acquisitions, net of dispositions - (743)
Drilling, completion and recompletion 22,383 11,675
Facilities and well equipment 11,643 13,853
Capitalized G&A 832 720
--------- ---------
Total oil and natural gas expenditures 35,334 27,227
Office equipment and furniture 25 54
--------- ---------
Total capital expenditures 35,359 27,281
Non-cash asset retirement obligations and
capitalized stock based compensation 1,530 380
--------- ---------
Total cash and non-cash capital additions $ 36,889 $ 27,661
--------- ---------
--------- ---------

Drilling statistics are shown below:
Three months ended March 31
------------------------------
2008 2007
----------- ------------
Gross Net Gross Net
----- ---- ------ -----
Gas 75 53.8 35 21.3
Oil 4 0.9 3 1.5
Dry 7 6.1 5 2.2
------------------------------
Total 86 60.8 43 25.0
------------------------------
------------------------------

Success rate (%) 92% 90% 88% 91%


During the first quarter of 2008, the Company drilled 86 gross (60.8 net) wells of which 90% were successful. Of these wells, 71 gross (56.0 net) wells were Edmonton Sands wells.

During the first quarter of 2008, the Company started three significant gas plant projects at Willesden Green, Wilson Creek and at Buck Lake that are expected to be completed in the second half of 2008.

Share Information

The Company's shares have been listed on the Toronto Stock Exchange since September 7, 2005 under the symbol "AXL". As of May 13, 2008, there were 87.3 million common shares outstanding and 6.4 million stock options outstanding. The Company's market capitalization at May 13, 2008 was $393 million.



Three Months Ended March 31
------------------------------------
Share Price on TSX 2008 2007
--------------- -----------------
High $ 3.95 $ 4.54
Low $ 2.44 $ 3.35
Close $ 3.65 $ 4.35
Volume 23,958,323 5,419,577

Shares outstanding at March 31 87,294,401 53,641,401
Market capitalization at March 31 $ 318,624,564 $ 233,340,094


Liquidity and Capital Resources

At March 31, 2008, the Company had outstanding bank loans of $87.9 million and a working capital deficiency of $26.8 million. The large working capital deficiency is due to accruals associated with the first quarter drilling.

Due to the strengthening of natural gas prices, the Company has increased its capital budget for 2008 to $85 million, net of dispositions of $7.5 million. Most of the capital expansion is to be spent in the fourth quarter of 2008. As such, Anderson Energy will review its capital budget throughout the year and adjust it upward or downward for any significant change 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. The Company currently has a $95.0 million extendible revolving term credit facility and a $10.0 million working capital credit facility with a syndicate of Canadian banks. In January 2008, the Company further increased its facilities through a $25 million supplemental credit facility. The supplemental facility decreases to $10 million on September 30, 2008 and must be repaid in full by December 31, 2008. 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 lender, 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 $1.4 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 25 million cubic feet per day of gas sales for various terms expiring between 2008 and 2015.

Subsequent to March 31, 2008, the Company completed three non-core property dispositions for total proceeds of $0.8 million. The Company also entered into a letter of intent to sell a larger non-core property for $6.7 million. The closing of this transaction is scheduled to occur in July 2008 and is subject to completion of a definitive purchase and sale agreement and other normal closing conditions.

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

The Canadian Accounting Standards Board ("AcSB") has announced that it will adopt International Financial Reporting Standards ("IFRS") effective January 1, 2011. This will require creating a January 1, 2010 opening balance sheet and restating 2010 results for comparative purposes as retroactive application with restatement will be required. On April 7, 2008 the AcSB released an exposure draft on the transition from Canadian Accounting Standards to IFRS.

One of the most significant impacts of the new standards is likely to be that there is no comparable IFRS standard for full cost companies, nor is there likely to be one by the time the new standards come into effect. Experience from overseas countries who have already adopted IFRS indicates a decline in oil and gas earnings and more volatility in earnings.

The Company is in the early stages of analyzing the effects of the new standards and a detailed transition plan has yet to be completed. Implementing the new standards will likely impact training for finance and accounting staff, information technology resources and costs, performance measures and budgets, banking agreements, contracts and compensation packages.

The effect on the Company's future balance sheet and earnings has not yet been determined.

Disclosure Controls and Procedures

There were no material changes in the Company's internal controls over financial reporting during the three months ended March 31, 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/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 188 gross (125 net) wells in 2008, with the Edmonton Sands project representing 85% 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 will also complete the three natural gas plant projects that commenced in the first quarter of 2008. When completed, they will 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 quarter 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)

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

Oil and gas revenue before
royalties $ 37,695 $ 27,775 $ 17,261 $ 18,440
Funds from operations $ 17,591 $ 12,564 $ 6,255 $ 8,972
Funds from operations per share
Basic $ 0.20 $ 0.14 $ 0.09 $ 0.15
Diluted $ 0.20 $ 0.14 $ 0.09 $ 0.15
Earnings (loss) $ 1,696 $ 4,867 $ (3,018) $ 368
Earning (loss) per share
Basic $ 0.02 $ 0.06 $ (0.04) $ 0.01
Diluted $ 0.02 $ 0.06 $ (0.04) $ 0.01
Capital expenditures,
including acquisitions
net of dispositions $ 35,359 $ 30,300 $ 135,966 $ 17,586
Cash from operating activities $ 17,416 $ 11,110 $ 5,801 $ 8,943
Daily sales
Natural gas (Mcfd) 39,210 35,672 26,860 22,928
Liquids (bpd) 1,345 1,150 843 602
BOE (bpd) 7,879 7,095 5,320 4,423
Average prices
Natural gas ($/Mcf) $ 7.55 $ 6.09 $ 5.00 $ 7.25
Liquids ($/bbl) $ 83.91 $ 72.28 $ 63.31 $ 58.18
BOE ($/BOE) $ 52.57 $ 42.55 $ 35.27 $ 45.81

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

Oil and gas revenue before
royalties $ 20,109 $ 16,820 $ 14,651 $ 15,452
Funds from operations $ 8,623 $ 7,996 $ 5,873 $ 6,728
Funds from operations per share
Basic $ 0.16 $ 0.15 $ 0.12 $ 0.14
Diluted $ 0.16 $ 0.15 $ 0.12 $ 0.13
Earnings (loss) $ (33) $ 846 $ (1,509) $ (1,675)
Earning (loss) per share
Basic $ - $ 0.02 $ (0.03) $ (0.03)
Diluted $ - $ 0.02 $ (0.03) $ (0.03)
Capital expenditures,
including acquisitions
net of dispositions $ 27,281 $ 20,662 $ 10,948 $ 15,994
Cash from operating activities $ 8,405 $ 8,651 $ 5,872 $ 9,056
Daily sales
Natural gas (Mcfd) 22,162 21,075 19,621 21,664
Liquids (bpd) 750 692 736 549
BOE (bpd) 4,444 4,205 4,006 4,160
Average prices
Natural gas ($/Mcf) $ 8.14 $ 6.82 $ 5.71 $ 6.05
Liquids ($/bbl) $ 52.59 $ 51.09 $ 62.14 $ 68.19
BOE ($/BOE) $ 50.28 $ 43.48 $ 39.75 $ 40.82


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)

----------------------------------------------------------------------------
----------------------------------------------------------------------------
March 31, December 31,
2008 2007
----------------------------------------------------------------------------

Assets

Current assets:
Cash $ 3 $ 2
Accounts receivable and accruals 32,835 31,540
Prepaid expenses and deposits 3,013 2,522
----------------------------------------------------------------------------
35,851 34,064

Property, plant and equipment (note 2) 484,360 461,896

Goodwill 35,364 35,364

----------------------------------------------------------------------------
$ 555,575 $ 531,324
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities and Shareholders' Equity

Current liabilities:
Accounts payable and accruals $ 62,647 $ 62,915

Bank loans (note 3) 87,904 67,981

Asset retirement obligations (note 4) 26,226 24,526

Future income taxes 42,245 41,450
----------------------------------------------------------------------------
219,022 196,872
Shareholders' equity:
Share capital (note 5) 334,147 334,147
Contributed surplus (note 5) 2,410 2,005
Deficit (4) (1,700)
----------------------------------------------------------------------------
336,553 334,452
Subsequent events (note 8)
----------------------------------------------------------------------------
$ 555,575 $ 531,324
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


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

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended
March 31,
2008 2007
----------------------------------------------------------------------------

Revenues
Oil and gas sales $37,695 $20,109
Royalties (8,688) (4,369)
Interest income 32 2
----------------------------------------------------------------------------
29,039 15,742
Expenses
Operating 8,694 4,893
General and administrative 1,552 1,668
Stock-based compensation 233 131
Interest and other financing charges 1,202 558
Depletion, depreciation and accretion 14,927 8,745
----------------------------------------------------------------------------
26,608 15,995

----------------------------------------------------------------------------
Earnings (loss) before taxes 2,431 (253)

Future income taxes (reduction) 735 (220)
----------------------------------------------------------------------------
Earnings (loss) for the period 1,696 (33)

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

----------------------------------------------------------------------------
Comprehensive income (loss) $ 1,696 $(1,498)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Deficit, beginning of period $(1,700) $(3,884)
Earnings (loss) for the period 1,696 (33)

----------------------------------------------------------------------------
Deficit, end of period $ (4) $(3,917)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Earnings (loss) per share (note 5)
Basic $ 0.02 $ -
Diluted $ 0.02 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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
March 31,
2008 2007
----------------------------------------------------------------------------

Cash provided by (used in):

Operations
Earnings (loss) for the period $ 1,696 $ (33)
Items not involving cash
Depletion, depreciation and accretion 14,927 8,745
Future income taxes (reduction) 735 (220)
Stock-based compensation 233 131
Asset retirement expenditures (100) (33)
Changes in non-cash working capital
Accounts receivable and accruals (4,825) 83
Prepaid expenses and deposits (148) (151)
Accounts payable and accruals 4,898 (117)
----------------------------------------------------------------------------
17,416 8,405

Financing
Increase in bank loans 19,923 15,924

Investments
Additions to property, plant and equipment (35,359) (28,024)
Proceeds on disposition of properties - 743
Changes in non-cash working capital
Accounts receivable and accruals 3,530 2,148
Prepaid expenses and deposits (343) (102)
Accounts payable and accruals (5,166) 898
----------------------------------------------------------------------------
(37,338) (24,337)

----------------------------------------------------------------------------
Increase (decrease) in cash 1 (8)

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

Cash, end of period $ 3 $ 3
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See note 6 for additional cash information.

See accompanying notes to the consolidated financial statements.

ANDERSON ENERGY LTD.
Notes to the Consolidated Financial Statements
Three months ended March 31, 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 any 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.



2. Property, plant and equipment

----------------------------------------------------------------------------
----------------------------------------------------------------------------
March 31, December 31,
2008 2007
----------------------------------------------------------------------------
Cost $609,951 $573,002
Less accumulated depletion and depreciation (125,591) (111,106)
----------------------------------------------------------------------------
Net book value $484,360 $461,896
----------------------------------------------------------------------------
----------------------------------------------------------------------------


At March 31, 2008, unproved property costs of $16.5 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 $176.4 million (December 31, 2007 - $177.8 million) have been included in the depletion and depreciation calculation.

For the three months ended March 31, 2008, $1.0 million (March 31, 2007 - $0.8 million) of general and administrative costs including $0.2 million (March 31, 2007 - $0.1 million) of stock-based compensation costs were capitalized. The future tax liability of $60,000 (March 31, 2007 - $48,000) 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 March 31, 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 March 31, 2008, there were no advances in U.S. funds. The average effective interest rate on advances in 2008 was 5.7% (March 31, 2007 - 5.6%).

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 March 31, 2008 there were no advances under the Supplemental Facility.

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 $55.7 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:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
March 31, December 31,
2008 2007
----------------------------------------------------------------------------
Balance, beginning of period $24,526 $14,905
Liabilities incurred during period 1,358 3,060
Liabilities assumed on corporate acquisition - 5,923
Liabilities settled in period (100) (742)
Accretion expense 442 1,380
----------------------------------------------------------------------------
Balance, end of period $26,226 $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 Amount
Common 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 March 31, 2008 and
December 31, 2007 87,294,401 $334,147
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 three months ended March 31, 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
Expirations and forfeitures (14,900) 4.44
----------------------------------------------------------------------------
Balance at March 31, 2008 6,282,406 $4.65
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Exercisable at March 31, 2008 3,731,639 $4.72
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Options outstanding Options exercisable
--------------------- ---------------------

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

$3.67 to $5.00 5,018,206 $ 4.00 4.2 2,952,206 $ 4.01
$5.01 to $7.50 538,800 6.17 3.2 285,500 6.34
$7.51 to $9.01 725,400 8.01 2.6 493,933 8.01
--------------------------------- ----------------------
Total at
March 31, 2008 6,282,406 $ 4.65 3.9 3,731,639 $ 4.72
--------------------------------- ----------------------
--------------------------------- ----------------------


The were no options issued in the three months ended March 31, 2008. The fair value of options issued in the three months ended March 31, 2007 ranged between $1.77 to $1.99 per option. The weighted average assumptions used in arriving at the values were: a risk-free interest rate of 4.0%, expected option life of four years, expected volatility of 50% and a dividend yield of 0%.

Per share amounts

During the three months ended March 31, 2008 there were 87,294,401 weighted average shares outstanding (March 31, 2007 - 53,641,401). On a diluted basis, there were 87,294,401 weighted average shares outstanding (March 31, 2007 - 53,641,401) after giving effect to dilutive stock options. At March 31, 2008, there were 6,282,406 options that were anti-dilutive (March 31, 2007 - 4,852,006).



Contributed surplus

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Amount
----------------------------------------------------------------------------
Balance at December 31, 2006 $ 820
Stock-based compensation 1,185
----------------------------------------------------------------------------
Balance at December 31, 2007 2,005
Stock-based compensation 405
----------------------------------------------------------------------------
Balance at March 31, 2008 $2,410
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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.



----------------------------------------------------------------------------
----------------------------------------------------------------------------
March 31, December 31,
2008 2007
----------------------------------------------------------------------------
Bank loans $ 87,904 $ 67,981
Current liabilities 62,647 62,915
Current assets (35,851) (34,064)
----------------------------------------------------------------------------
Total debt $114,700 $ 96,832
----------------------------------------------------------------------------

Cash from operating activities in quarter $ 17,416 $ 11,110
Changes in non-cash working capital 75 1,404
Asset retirement obligations 100 50
----------------------------------------------------------------------------
Funds from operations in quarter $ 17,591 $ 12,564
Annualized current quarter funds from
operations $ 70,364 $ 50,256
----------------------------------------------------------------------------
Total debt to funds from operations 1.6 1.9
----------------------------------------------------------------------------
----------------------------------------------------------------------------


At March 31, 2008, the Company's total debt to annualized funds from operations was 1.6 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 revolving term credit facility and working capital credit 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):

----------------------------------------------------------------------------
----------------------------------------------------------------------------
March 31, March 31,
2008 2007
----------------------------------------------------------------------------

Interest paid $943 $538
Interest received (35) (8)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 March 31, 2008, the maximum credit exposure is the carrying amount of the accounts receivable and accruals of $32.8 million (December 31, 2007 - $31.5 million). As at March 31, 2008, the Company's receivables consisted of $16.8 million from joint venture partners and other trade receivables and $16.0 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 $16.0 million of revenue accruals and receivables from petroleum and natural gas marketers, $14.0 million was received on April 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 March 31, 2008, the largest amount owing from one partner is $2.5 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 March 31, 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 March 31, 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 March 31, 2008 the Company considers it receivables to be aged as follows:



----------------------------------------------------------------------------
Aging March 31, 2008
----------------------------------------------------------------------------
Not past due $25,462
Past due by less than 120 days 3,186
Past due by more than 120 days 4,187
----------------------------------------------------------------------------
Total $32,835
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 March 31, 2008:



----------------------------------------------------------------------------
Financial Liabilities less than 1 Year 1 -2 Years
----------------------------------------------------------------------------
Accounts payable and accrued liabilities $62,647 $ -
Bank debt - principal - 87,904
----------------------------------------------------------------------------
Total $62,647 $ 87,904
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 March 31, 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 March 31, 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 three months ended March 31, 2007 were $1.2 million and were included in oil and gas sales.

There were no commodity price risk contracts outstanding at March 31, 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 three months ended March 31, 2008, if interest rates had been 1% lower with all other variables held constant, earnings for the period would have been $99,000 (March 31, 2007 - $47,000) 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 March 31, 2008.

8. Subsequent events

Subsequent to March 31, 2008, the Company completed the dispositions of certain working interests in three non-core properties for total proceeds of $0.8 million. The Company has also entered into a letter of intent to dispose of certain working interests in another non-core property for $6.7 million. The closing of this transaction is scheduled to occur in July 2008 and is subject to completion of a definitive purchase and sale agreement and other normal closing conditions.



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 David M. Spyker
Vice President, Business Development

Auditors
KPMG LLP
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


Contact Information

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