Anderson Energy Ltd.
TSX : AXL

Anderson Energy Ltd.

August 14, 2007 08:45 ET

Anderson Energy Ltd. Announces 2007 Second Quarter Results

CALGARY, ALBERTA--(Marketwire - Aug. 14, 2007) - 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, 2007.

Highlights:

- Drilling results for the three months ended June 30, 2007 resulted in 5 gross (4.4 net) gas wells drilled. Drilling activity was less than planned due to an extended spring breakup, followed by significant rainfall resulting in wet field conditions.

- Second quarter production averaged 4,423 BOED, a 6% increase over the second quarter of 2006 and similar to the first quarter of 2007. Production was negatively impacted by third party plant turnarounds and wet field conditions that delayed the tie-in of wells.

- The average natural gas price received was $7.25/Mcf in the second quarter of 2007, a 20% increase over the second quarter of 2006 and an 11% decrease from the first quarter of 2007.

- Funds from operations were $9.0 million ($0.15 per share), a 33% increase from the second quarter of 2006 and a 4% increase from the first quarter of 2007.

- On July 25, 2007, the Company announced an agreement to acquire oil and natural gas assets in its core area of Greater Sylvan Lake for cash consideration of $117.1 million before closing adjustments ("the Acquisition"). The Acquisition will add over 2,100 BOED of production, 6.7 MMBOE of total proved and 9.6 MMBOE of total proved plus probable reserves. The Acquisition will be financed by the issuance of subscription receipts for common shares of the Company and increased credit facilities. Closing is expected on August 31, 2007.

- On August 13, 2007, the Company closed a $100.2 million subscription receipts financing. Funds will be held in escrow until the Acquisition is closed. The subscription receipts trade on the TSX under the symbol AXL.R.

- As a result of the anticipated Acquisition, the Company has revised its estimated 2007 average production guidance upward to 5,600 to 6,000 BOED and has revised its estimated 2007 exit production guidance upward to 8,000 to 8,400 BOED, assuming the Acquisition closes on August 31, 2007.

- The Company's drilling inventory has grown to 1,241 gross (571 net) locations as of June 30, 2007, including the Acquisition. Net of wells drilled, the drilling inventory has grown 35% on a net well basis in the quarter.

- The Company's Edmonton Sands acreage position is 307 gross (167 net) sections as of June 30, 2007, including the Acquisition. This position has grown 59% since December 31, 2006.



Financial and Operating Highlights

Three months ended % Six months ended %
June 30 Change June 30 Change
------------------------------------------------ --------------------------
2007 2006 2007 2006
Financial
(thousands of dollars, except share data)

Total oil and gas
revenue $ 18,440 $ 15,452 19% $ 38,549 $ 32,341 19%
Funds from
operations $ 8,972 $ 6,728 33% $ 17,595 $ 15,332 15%
Per common share
- basic $ 0.15 $ 0.14 7% $ 0.31 $ 0.31 0%
- diluted $ 0.15 $ 0.13 15% $ 0.31 $ 0.31 0%
Earnings (loss) $ 368 $ (1,675) 122% $ 335 $ (2,871) 112%
Per common share
- basic $ 0.01 $ (0.03) 133% $ 0.01 $ (0.06) 117%
- diluted $ 0.01 $ (0.03) 133% $ 0.01 $ (0.06) 117%
Field capital
expenditures 10,290 15,551 (34%) 38,694 45,564 (15%)
Acquisitions, net
of dispositions 9,145 1,102 730% 8,402 4,809 75%
Debt, net of
working capital 43,668 50,043 (13%)
Shareholders' equity $235,483 186,615 26%
Average shares
outstanding
(thousands)
Basic 59,588 49,108 21% 56,631 48,693 16%
Diluted 60,059 50,054 20% 57,104 49,703 15%
Ending shares
outstanding
(thousands) 61,594 49,305 25%
Operating (6 Mcf:1bbl
conversion)
Average daily sales
Natural gas (Mcfd) 22,928 21,664 6% 22,547 21,234 6%
Light/medium
crude oil (bpd) 504 379 33% 537 421 28%
NGL (bpd) 98 170 (42%) 139 161 (14%)
Barrels of oil
equivalent (BOED) 4,423 4,160 6% 4,434 4,121 8%
Average sales price
Natural gas ($/Mcf) 7.25 6.05 20% 7.68 6.71 14%
Light/medium
crude oil ($/bbl) 58.07 67.91 (14%) 55.82 58.87 (5%)
NGL ($/bbl) 58.71 68.80 (15%) 52.26 60.22 (13%)
Barrels of oil
equivalent ($/BOE) 45.49 40.50 12% 47.47 42.92 11%

Royalties ($/BOE) 7.37 9.13 (19%) 9.14 9.75 (6%)
Operating costs
($/BOE) 10.97 9.96 10% 11.60 9.28 25%
Operating netbacks
($/BOE) 27.47 21.73 26% 27.30 24.33 12%
General and
administrative
($/BOE) 4.49 3.23 39% 4.50 3.19 41%
Wells drilled
(gross) 5 16 (69%) 48 54 (11%)


Production:

Second quarter production averaged 4,423 BOED, similar to the previous quarter due to downtime as a result of significant plant turnarounds, all of which are now complete. Extended rain also hampered drilling and tie-in operations with only two wells connected for production in the quarter. Current production is estimated to be 4,950 BOED with approximately 1,000 BOED behind pipe.

The wet ground conditions continued into late July, but the Company has brought in additional equipment to accelerate its planned activities in the second half of 2007.

With the expected closing of the Acquisition on August 31, 2007, the Company has revised its annual and exit guidance upward to:



2007 average 5,600 to 6,000 BOED
2007 exit 8,000 to 8,400 BOED


The Company was within its previous guidance estimate without the Acquisition.

Operations:

During the second quarter of 2007, the Company drilled 5 gross (4.4 net) Edmonton Sands gas wells. Although the second quarter is not historically an active drilling quarter, the Company experienced an extended spring breakup followed by extensive rainfall, which slowed its drilling program and virtually halted its well tie-in program. In the balance of the year, the Company is planning to drill 95 gross (55 net) wells and at various times in the third quarter, the Company will have between one and three operated drilling rigs working in the field.

Capital spending in the quarter was $19.4 million, which included $2.0 million spent on drilling and completions, $5.6 million spent on facilities and $9.2 million (net of adjustments) spent on a property acquisition. One of the five large compression and pipeline projects was completed in the second quarter and work continues on the remaining projects. A second project was recently completed and the others are expected to be completed later in the third quarter.

The Company's current capital forecast is $73 million for exploration and development activities net of minor property dispositions, and $200 million in total including acquisitions. Total drilling planned for 2007 is 143 gross (84 net) locations with Edmonton Sands representing 83% of the net locations and CBM representing 8% of the net locations.

Acquisitions:

On June 29, 2007, the Company closed a $9.2 million property acquisition and added approximately 240 BOED of production in the Sylvan Lake area.

On July 25, 2007, the Company announced a strategic $117.1 million asset acquisition in and around the Company's Sylvan Lake Edmonton Sands project area in Central Alberta. The Acquisition is expected to close on August 31, 2007. The Acquisition is being financed by the issuance of subscription receipts for common shares of the Company and increased credit facilities.

On August 13, 2007, the Company closed the subscription receipts financing. Funds will be held in escrow until the Acquisition is closed, which is expected to be on August 31, 2007. The subscription receipts trade on the TSX under the symbol AXL.R.

Highlights of the Acquisition are set forth below:

1. Reserves:

a) Reserves of 5.1 MMBOE proved and 6.8 MMBOE proved plus probable (effective May 1, 2007) have been estimated by the vendor's third party engineering firm.

b) Additional reserves of 1.6 MMBOE proved and 2.8 MMBOE proved plus probable associated with the Edmonton Sands formation have been estimated by the Company's internal qualified reserves evaluator. These additional reserves were estimated using a reserves methodology consistent with that employed by the Company's independent engineers in the December 31, 2006 Anderson Energy reserves report. The Company is adding 55 gross (32 net) sections of Edmonton Sands prospective land through the Acquisition.

c) Total reserves are estimated to be 6.7 MMBOE proved and 9.6 MMBOE proved plus probable.

2. Production:

a) Average production was 2,146 BOED for the three months ended March 31, 2007.

b) 75% of production is operated.

c) 75% of production is natural gas, 19% is natural gas liquids and 6% is light oil.

d) Operating costs averaged $10.17 per BOE in 2006.

3. Facilities:

a) There are three key gas plants associated with the Acquisition where Anderson Energy currently has no working interest capacity and is currently paying outside processing fees on 2.8 MMCFD of production. As well, there are various other compressors and gathering lines where Anderson Energy is not an owner and is currently paying a third party processing fee. The Company will achieve operating cost savings for current Anderson Energy production through the acquisition of these facilities. These various facilities interests will become more strategic to Anderson Energy as the Company ramps up its Edmonton Sands drilling program.

b) In the Willesden Green area, the Company is installing compression for recent Edmonton Sands discoveries, which will benefit production from the acquired lands which are negatively impacted by poor service factors.

4. Drilling Locations and Other Opportunities:

a) The Company has identified 160 gross (86 net) drilling locations prospective for Edmonton Sands on the acquired lands.

b) In addition, the Company has identified:

i) 6 gross (4.8 net) locations prospective for Glauconite infill drilling in the Bigoray Glauconitic "I" Pool. After closing the Acquisition, the Company is planning to apply for two well per section holdings and could commence drilling these lands in 2008. This Glauconite pool is very similar to other Glauconite pools in the Hoadley Glauconite trend which have been downspaced to three wells per section. This opportunity was not identified in the vendor engineering report.

ii) In the Strachan area, the Company is planning to install compression and wellbore optimization in the Leduc and Elkton pools in this area. This project could commence in 2008. The potential uplift in production from this project is approximately 2.5 MMCFD.

iii) Other opportunities include 6 gross (4.8 net) drilling locations and 9 gross (5.5 net) re-completion opportunities in plays other than the Edmonton Sands and Glauconite.

5. The Assets are being acquired through the purchase of a subsidiary of the vendor and it is expected that the tax pools associated with the Acquisition will not exceed undepreciated capital cost of $23.4 million. The Company has approximately $215 million in tax pools, including over $50 million in Canadian Exploration Expense at June 30, 2007 and does not expect to be cash taxable following the Acquisition for at least three years based on current modeling.

6. Purchase price parameters (net of $7 million in value attributed to plant synergy, 25,334 net acres of undeveloped land and seismic) are $16.27/BOE proved and $11.53/BOE proved plus probable without future development capital, $20.23/BOE proved and $16.45/BOE proved plus probable including future development capital and $51,300/BOED of current production. Anderson Energy's technical review of the acquired assets suggests meaningful drilling upside that, over time, may reduce these purchase price parameters.

Outlook:

The Company's net well drilling inventory has grown 35% since the end of the first quarter. The Company's net Edmonton Sands land position has grown 59% since the start of the year.

The Company has seen lower costs to drill and complete Edmonton Sands wells, through the reduction of service costs and the application of more efficient processes and new technology. This summer's costs are approximately 30% lower than 2006 and we are continuing to see reductions.

Natural gas prices have fallen significantly in the third quarter compared to the second quarter due to concerns over U.S. natural gas storage levels increasing on a relative basis for the last 8 weeks when compared to 2006. Due to a warm European winter, LNG cargoes originally destined for Europe were diverted to the United States from March to July of this year. This contributed to higher U.S. natural gas storage levels. So far this summer, natural gas demand associated with air conditioning has been down as a result of a mild summer in the south. Over time, the reduction in Canadian natural gas drilling activity due to lower natural gas prices, as well as the anticipated increase in natural gas demand from oil sands projects, should reduce the supply of natural gas and help correct the storage imbalance. An early start to winter would have a positive influence on natural gas prices in 2007.

In the balance of the year, the Company will continue to add to its opportunity base through additional Edmonton Sands farm-ins and will selectively evaluate potential property acquisitions, in addition to ramping up its drilling and tie-in operations on its existing and newly acquired properties.

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

Brian H. Dau, President & Chief Executive Officer

August 14, 2007

Anderson Energy Ltd.

Management's Discussion and Analysis for the Six Months Ended June 30, 2007 and 2006:

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 six months ended June 30, 2007 and 2006 and is based on information available as of August 13, 2007.

The following information is based on financial statements prepared by management in accordance with Canadian generally accepted accounting principles ("GAAP"). Production and reserve 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 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. Anderson Energy believes that funds from operations represent both an indicator of the Company's performance and a funding source for on-going operations. Production volumes and reserves are commonly expressed on a barrels 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.

Review of Financial Results:

Overview:

Sales volumes for the three months ended June 30, 2007 were 4,423 BOED, which was similar to the previous quarter. Average production for the month of June 2007 was significantly affected by plant turnarounds during the month and wet field conditions that delayed the tie-in of wells.

Funds from operations were $9.0 million or $0.15 per share in the quarter, 4% higher than the first quarter of 2007. The impact of lower gas prices was offset by lower expenses in the quarter.

Capital expenditures were $19.4 million and included a $9.2 million acquisition in Sylvan Lake at the end of the quarter. An extended spring break up, followed by significant rainfall creating wet ground conditions in the Company's main area of operations, resulted in lower than anticipated drilling and tie-in activity.

On April 24, 2007, the Company issued 7,935,000 common shares for net proceeds of $32.5 million under a bought deal financing and an associated over-allotment option.

The result was an overall decrease in debt, net of working capital to $43.7 million at June 30, 2007.

Subsequent to June 30, 2007, the Company announced a $117.1 million acquisition in its core area of Sylvan Lake. The transaction is being financed by a $100.2 million bought deal equity financing and an increase in the Company's credit facility from $75 to $105 million. Closing is expected on August 31, 2007.

Revenue and Production:

Production for the three months ended June 30, 2007 was 4,423 BOED, similar to the previous quarter and 6% higher than the 4,160 BOED produced in the corresponding period of 2006. During the quarter, production was negatively impacted by third party plant turnarounds and well tie-in delays due to wet ground conditions in and around the Edmonton Sands core area of operations. For the six months ended June 30, 2007 production increased 8% to 4,434 BOED from 4,121 BOED in the corresponding period of 2006.

Gas sales comprised 86% of production at 22.9 MMcfd in the second quarter of 2007, an increase from 22.2 MMcfd in the first quarter of 2007 and 21.7 MMcfd in the same period of 2006. Oil production averaged 504 bpd in the second quarter of 2007 compared to 571 bpd in the first quarter of 2007 and 379 bpd in the second quarter of 2006. Natural gas liquids production averaged 98 bpd in the second quarter of 2007 compared to 179 bpd in the first quarter of 2007 and 170 bpd in the second quarter of 2006. The decrease in natural gas liquids production in the quarter was the result of an adjustment to 2006 estimates. Natural gas liquids production before this adjustment was 133 bpd in the second quarter.

Gas sales made up 82% of Anderson Energy's total oil and gas sales for the three months ended June 30, 2007 compared to 81% of total oil and gas sales for the first quarter of 2007 and 77% of total oil and gas sales for the three months ended June 30, 2006. The percentage reflects increased overall production of gas in the second quarter, partially offset by lower gas prices than the first quarter of 2007. Revenue for the second quarter of 2007 increased 19% to $18.4 million from $15.5 million in the second quarter of 2006 as a result of both higher realized gas prices and higher production volumes. For the six months ended June 30, 2007 oil and gas revenue was $38.5 million, 19% higher than the same period in 2006.

The following tables outline production revenue, volumes and average sales prices for the three and six month periods.



Three months ended Six months ended
June 30 June 30
----------------------------------------------------------------------
Oil and Natural Gas Revenue 2007 2006 2007 2006
(thousands of dollars)
Natural gas $ 15,125 $ 11,922 $ 30,196 $ 25,774
Natural gas hedging gains - - 1,157 -
Oil 2,662 2,344 5,429 4,482
NGL 526 1,066 1,311 1,757
Royalty and other 127 120 456 328
----------------------------------------------------------------------
Total $ 18,440 $ 15,452 $ 38,549 $ 32,341
----------------------------------------------------------------------

Production
Natural gas (Mcfd) 22,928 21,664 22,547 21,234
Oil (bpd) 504 379 537 421
NGL (bpd) 98 170 139 161
----------------------------------------------------------------------
Total (BOED) 4,423 4,160 4,434 4,121
----------------------------------------------------------------------

Prices
Natural gas ($/Mcf) $ 7.25 $ 6.05 $ 7.68 $ 6.71
Oil ($/bbl) 58.07 67.91 55.82 58.87
NGL ($/bbl) 58.71 68.80 52.26 60.22
Total ($/BOE) $ 45.49 $ 40.50 $ 47.47 $ 42.92


Anderson Energy's average natural gas price was $7.25/Mcf for the three months ended June 30, 2007, lower than the $8.14/Mcf realized in the first quarter of 2007 and higher than the $6.05/Mcf realized in the second quarter of 2006. For the six months ended June 30, 2007, realized natural gas prices were $7.68/Mcf, 14% lower than the $6.71/Mcf realized in the same period of 2006. The natural gas price in the first half of 2007 includes hedging gains of $1.2 million. The 2007 year-to-date gas price before hedging gains was $7.40/Mcf.

Historically, Anderson Energy has sold most of its natural gas at Alberta spot market prices. 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 20 MMcfd of natural gas sales for various terms ranging from one to three years, and including new firm service associated with the $9.2 million property acquisition completed at the end of the quarter.

Hedging Contracts:

In November 2006, as part of its risk management program, the Company entered into fixed price natural gas contracts to manage commodity price risk. The Company had financial swap contracts to sell 18,000 GJ/day of natural gas at an average price of $7.79/GJ at AECO for January to March 2007. This represented approximately 17 MMcfd of natural gas sales for January to March 2007. No commodity price contracts were outstanding after March 31, 2007.

Royalties:

Royalties were $3.0 million (16% of revenue) in the second quarter of 2007 lower than both the first quarter of 2007 and the second quarter of 2006. Royalties in the second quarter of 2007 were reduced by recent assessments related to 2006 gas cost allowance. For the six months ended June 30, 2007, royalties were $7.3 million (19% of revenue), compared to $7.3 million (22% of revenue) in the corresponding period of 2006. In 2006, the Company received Alberta Royalty Tax Credits ("ARTC") of $500,000. This program has been discontinued in 2007. The Company expects 2007 royalties to increase overall as production increases. The average royalty rate as a percentage of revenue is expected to be higher in future quarters as the second quarter was reduced by the gas cost allowance assessments.

Operating Expenses:

Operating expenses were $10.97/BOE ($4.4 million) in the second quarter, 10% higher than the $9.96/BOE recorded in the second quarter of 2006 due to overall increases in costs, significant plant turnarounds in June 2007 resulting in lower volumes and some third party gas processing adjustments. For the six months ended June 30, 2007, operating costs were $11.60/boe ($9.3 million), 25% higher than the $9.28/BOE ($6.9 million) recorded in the corresponding period of 2006. In the first quarter of 2007, operating costs were impacted by a series of workovers, pump changes and compressor repairs over the winter months as well as third party 2006 gas processing adjustments. In addition, the shut-in at Chinchaga, one of the Company's lower operating cost properties on a BOE basis, increased operating costs per BOE in the first quarter of 2007. On a BOE basis, the Company expects operating costs to be similar to the second quarter for the balance of the year.



Operating Netback:
------------------
Three months ended Six months ended
June 30 June 30
--------------------------------------------
2007 2006 2007 2006
(thousands of dollars)
Revenue $ 18,440 $ 15,452 $ 38,549 $ 32,341
Royalties (2,967) (3,456) (7,336) (7,270)
Operating expenses (4,417) (3,772) (9,310) (6,920)
--------------------------------------------
$ 11,056 $ 8,224 $ 21,903 $ 18,151
--------------------------------------------

Sales (MBOE) 402.5 378.6 802.5 745.9
($/BOE)
Revenue $ 45.81 $ 40.82 $ 48.04 $ 43.36
Royalties (7.37) (9.13) (9.14) (9.75)
Operating expenses (10.97) (9.96) (11.60) (9.28)
--------------------------------------------
$ 27.47 $ 21.73 $ 27.30 $ 24.33
--------------------------------------------


General and Administrative Expenses:

General and administrative expenses ("G&A") consist largely of salaries, rent, computer and other office costs. G&A expenses were $4.49/BOE ($1.8 million) in the second quarter of 2007, similar to the $4.50/BOE in the first quarter of 2007 and 39% higher than the $3.23/BOE ($1.2 million) recorded in the second quarter of 2006. For the six months ended June 30, 2007, G&A costs were $4.50/BOE ($3.6 million), 41% higher than the $3.19/boe ($2.4 million) incurred in the same period of 2006. Higher G&A costs were primarily due to higher than anticipated 2006 reserve report costs accounted for in 2007 and a one-time staff retention bonus paid in April 2007. Overhead recoveries were lower in the second quarter due to lower capital spending. Management anticipates that G&A will decrease on a per boe basis in the second half of 2007 as production increases.



Three months ended Six months ended
June 30 June 30
---------------------------------------
2007 2006 2007 2006

General and administrative (gross) $ 2,875 $ 2,401 $ 5,937 $ 5,021
Overhead recoveries (302) (417) (729) (1,112)
Capitalized (765) (760) (1,601) (1,527)
--------------------------------------------------------------------------
General and administrative (net) $ 1,808 $ 1,224 $ 3,607 $ 2,382
--------------------------------------------------------------------------

General and administrative ($/BOE) $ 4.49 $ 3.23 $ 4.50 $ 3.19

% G&A capitalized 27% 32% 27% 30%


Capitalized general and administrative costs are limited to salaries, stock-based compensation and associated office rent of staff involved in capital activities.

Interest Expense:

Interest expense was $0.5 million in the second quarter, lower than the $0.6 million in the first quarter of 2007 due to the April 2007 equity financing that reduced debt levels. For the six months ended June 30, 2007, interest expense was $1.0 million, 32% higher than the $0.8 million in the corresponding period of 2006 as a result of higher average debt levels in 2007 as well as higher interest rates.

Depletion and Depreciation:

Depletion and depreciation on a per BOE basis was $21.31 ($8.6 million) in the second quarter, similar to the $21.19 ($8.5 million) recorded in the first quarter of 2007 and 23% lower than the $27.59 ($10.4 million) in same period of 2006. For the six months ended June 30, 2007, depletion and depreciation per BOE decreased 22% to $21.25 ($17.1 million) compared to $27.29 ($20.4 million) recorded in the corresponding period of 2006. Depletion and depreciation expense is calculated using proved reserves only and the decrease in the expense on a BOE basis was due to a higher percentage of the Company's total reserves being classified as proved in 2007.

Asset Retirement Obligations:

As a result of obligations assumed with the Sylvan Lake property acquisition at the end of June, the Company incurred $1.7 million in asset retirement obligations in the second quarter of 2007, compared to $0.3 million in the first quarter of 2007 and $0.7 million in the second quarter of 2006. Accretion expense was $0.3 million for the second quarter of 2007, $0.3 million for the first quarter of 2007 and $0.2 million in the second quarter of 2006 and is included in depletion, depreciation and accretion expense.

Income Taxes:

The Company is not currently taxable. The Company has approximately $215 million in available tax pools as of June 30, 2007.

In the second quarter, the Company recorded a $0.4 million future income tax recovery, compared to a $2.4 million recovery in the corresponding period in 2006. For the six months ended June 30, 2007, the future income tax recovery was $0.6 million compared to a $2.9 million recovery in the same period of 2006. Lower future income tax recoveries were due to smaller pretax losses.

The effect of enacted federal income tax rate reductions resulted in a $0.3 million reduction in the future tax provision in the second quarter of 2007.

Funds from Operations:

Funds from operations for the three months ended June 30, 3007 were $9.0 million, compared to $8.6 million in the first quarter of 2007 and $6.7 million in the second quarter of 2006. On a per share basis, funds from operations were $0.15 for the second quarter of 2007, $0.16 for the first quarter of 2007 and $0.14 for the second quarter of 2006. For the six months ended June 30, 2007, funds from operations were $17.6 million compared to $15.3 million in the corresponding period in 2006. Higher funds from operations are the result of both higher production volumes and higher gas prices, offset to some extent by higher costs.

Earnings:

The Company reported earnings of $0.4 million for the three months ended June 30, 2007, compared to a loss of $33,000 in the first quarter of 2007 and a loss of $1.7 million in the second quarter of 2006. For the six months ended June 30, 2007, the Company recorded earnings of $0.3 million compared to a loss of $2.9 million in the same period in 2006. The increase was due to lower depletion, depreciation and accretion expense in 2007.

Capital Expenditures:

The Company spent $47.1 million in capital additions in the first six months of 2007 and $19.4 million in the second quarter. The breakdown of expenditures is shown below:



Three months ended Six months ended
(thousands of dollars) June 30, 2007 June 30, 2007
-------------------------------------
Land, geological & geophysical costs $ 122 $ 1,844
Property acquisitions, net of dispositions 9,145 8,402
Drilling, completion and recompletion 2,006 13,681
Facilities and well equipment 5,647 19,500
Office equipment and furniture 14 68
Capitalized G&A 766 1,601
Asset retirement costs 1,735 2,000
--------------------------------------------------------------------------
Total $ 19,435 $ 47,096
--------------------------------------------------------------------------

Drilling statistics are shown below:

Three months ended June 30 Six months ended June 30
2007 2006 2007 2006
Gross Net Gross Net Gross Net Gross Net
Gas 5.0 4.4 14.0 7.3 40.0 25.7 44.0 20.3
Oil - - 1.0 0.9 3.0 1.5 6.0 4.0
Dry - - 1.0 1.0 5.0 2.2 4.0 3.2
--------------------------------------------------------------------------
Total 5.0 4.4 16.0 9.2 48.0 29.4 54.0 27.5
--------------------------------------------------------------------------

Success rate (%) 100% 100% 94% 89% 90% 93% 93% 88%


In the second quarter of 2007, 100% of the gross wells drilled were drilled in the Sylvan Lake area.

Liquidity and Capital Resources:

Early in 2007, the Company increased its bank loan facility from $55 million to $75 million. The $20 million increase in the bank line is dedicated to expenditures made in the Sylvan Lake Edmonton Sands shallow gas play. In conjunction with the acquisition announced on July 25, 2007, the Company expects to further increase its bank loan facility to $105 million. As of June 30, 2007, total long term debt plus net working capital deficiency was $43.7 million.

On April 24, 2007, the Company issued 7,935,000 common shares at a price of $4.35 per share for gross proceeds of $34.5 million ($32.5 million after commission and expenses).

On August 13, 2007, the Company issued 25.7 million subscription receipts on a bought deal basis for gross proceeds of $100.2 million to partially finance the Acquisition announced on July 25, 2007. Funds will be held in escrow until the Acquisition has closed, which is expected to be August 31, 2007. In addition, the underwriters have been granted an overallotment option to purchase up to 3.855 million additional subscription receipts which may be exercised up to 30 days after closing of the offering.

As of August 13, 2007, there are 61.6 million common shares outstanding, 4.9 million stock options outstanding and 25.7 million subscription receipts outstanding.

Contractual Obligations:

On February 28, 2007, the Company renounced $15 million of qualifying expenditures under flow through share agreements entered into in 2006. The Company has spent approximately $14.9 million on these expenditures to June 30, 2007.

On July 25, 2007, the Company announced that it had entered into an agreement to acquire oil and natural gas assets in the Greater Sylvan Lake area for total cash consideration of $117.1 million before closing adjustments. Completion of this transaction is subject to customary industry conditions and is expected to close on August 31, 2007. The Assets are being acquired through the purchase of a subsidiary of the vendor and it is expected that the tax pools associated with the Acquisition will not exceed undepreciated capital cost of $23.4 million. The Company does not expect to be cash taxable following the Acquisition.

Changes in Accounting Policies:

Effective January 1, 2007, the Company adopted the Canadian Institute of Chartered Accountants ("CICA") Section 3855 "Financial Instruments - Recognition and Measurement," Section 3865 "Hedges", Section 1530 "Comprehensive Income" and Section 3251 "Equity".

The adoption of the new standards did not have a material effect on the consolidated financial statements.

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, 2007.

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

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.

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.

On April 26, 2007, the Federal Government released its Action Plan to Reduce Greenhouse Gases and Air Pollution (the "Action Plan"), also known as ecoACTION and that includes the Regulatory Framework for Air Emissions. This Action Plan covers not only large industry, but regulates the fuel efficiency of vehicles and the strengthening of energy standards for a number of energy-using products. Regarding large industry and industry related projects, the Government's Action Plan intends to achieve the following: (i) an absolute reduction of 150 megatonnes in greenhouse gas emissions by 2020 by imposing mandatory targets; and (ii) air pollution from industry is to be cut in half by 2015 by setting certain targets. New facilities using cleaner fuels and technologies will have a grace period of three years. In order to facilitate companies' compliance with the Action Plan's requirements, while at the same time allowing them to be cost-effective, innovative and adopt cleaner technologies, certain options are provided. These are: (i) in-house reductions; (ii) contributions to technology funds; (iii) trading of emissions with below-target emission companies; (iv) offsets; and (v) access to Kyoto's Clean Development Mechanism.

On March 8, 2007, the Alberta Government introduced Bill 3, the Climate Change and Emissions Management Amendment Act, which intends to reduce greenhouse gas emission intensity from large industries. Bill 3 states that facilities emitting more than 100,000 tonnes of greenhouse gases a year must reduce their emissions intensity by 12% starting July 1, 2007.

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 those requirements on Anderson Energy and its operations and financial condition. Bill 3 does not currently have an impact on the Company as we do not own any facilities emitting in excess of 100,000 tonnes per year.

On February 16, 2007, the Alberta government announced that a review of the province's royalty and tax regime (including income tax and freehold mineral taxes) pertaining to oil and gas resources, including oil sands, conventional oil and gas, and coalbed methane, will be conducted by a panel of experts with the assistance of individual Albertans and key stakeholders. The review panel is to produce a final report that will be presented to the Minister of Finance by August 31, 2007.

Business Prospects:

The Company has an excellent drilling inventory with over six years of development drilling locations in its three core resource plays, Sylvan Lake Edmonton Sands, Horseshoe Canyon Coal Bed Methane and northeast B.C. The Company will be focusing on drilling the remaining 95 gross (55 net) wells in its revised capital budget of 143 gross (84 net) wells. The Company is continually working with its suppliers and service companies to bring the cost of services down. 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's 2007 average production guidance has been revised upward to 5,600 to 6,000 BOED, assuming the closing of the Acquisition on August 31, 2007. Exit production guidance is 8,000 to 8,400 BOED for 2007. Some of the risks associated with these estimates include gas plant capacity, regulatory issues and weather problems.

The Company will continue to develop its Edmonton Sands drilling opportunities, explore for new Edmonton Sands prospective areas and drill on its CBM acreage and other prospects in North Central and Eastern Alberta. The Company will likely continue to consolidate its land holdings and conduct further dispositions.



Quarterly Information:
(in thousands, except per share amounts)

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

Oil & 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)
Earnings (loss) per share
Basic $ 0.01 $ - $ 0.02 $ (0.03)
Diluted $ 0.01 $ - $ 0.02 $ (0.03)
Capital expenditures, including $ 19,435 $ 27,661 $ 22,068 $ 11,592
acquisitions
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) $ 45.49 $ 49.45 $ 42.62 $ 39.41

Q2 2006 Q1 2006 Q4 2005 Q3 2005
------- ------- ------- -------

Oil & gas revenue before royalties $ 15,452 $ 16,889 $ 22,894 $ 12,147
Funds from operations $ 6,728 $ 8,604 $ 13,187 $ 6,745
Funds from operations per share
Basic $ 0.14 $ 0.18 $ 0.28 $ 0.18
Diluted $ 0.13 $ 0.17 $ 0.27 $ 0.17
Earnings (loss) $ (1,675) $ (1,196) $ 1,762 $ 543
Earnings (loss) per share
Basic $ (0.03) $ (0.02) $ 0.04 $ 0.01
Diluted $ (0.03) $ (0.02) $ 0.04 $ 0.01
Capital expenditures, including $ 16,653 $ 33,720 $ 25,635 $ 14,960
acquisitions
Daily sales
Natural gas (Mcfd) 21,664 20,799 18,785 11,991
Liquids (bpd) 549 614 577 250
BOE (bpd) 4,160 4,081 3,708 2,249
Average prices
Natural gas ($/Mcf) $ 6.05 $ 7.40 $ 11.39 $ 9.68
Liquids ($/bbl) $ 68.19 $ 51.15 $ 53.56 $ 61.97
BOE ($/BOE) $ 40.50 $ 45.41 $ 66.05 $ 58.49


ADVISORY:

Certain information regarding Anderson Energy Ltd. in this news release including 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, productive capacity of the wells, timing of construction of facilities, expected production rates, dates of commencement of production, capital expenditures and timing thereof and extent of reserve additions, may constitute forward-looking statements under applicable securities laws and necessarily involve risks 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 effect 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,
2007 2006
---------------------------------------------------------------------------
Assets
Current assets:
Cash $ 10 $ 11
Accounts receivable and accruals 25,357 28,885
Prepaid expenses and deposits 2,053 1,968
---------------------------------------------------------------------------
27,420 30,864

Property, plant and equipment (note 2) 302,321 272,180

Goodwill 14,320 14,320
---------------------------------------------------------------------------
$344,061 $317,364
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Liabilities and Shareholders' Equity

Current liabilities:
Accounts payable and accruals $ 44,352 $ 51,890

Bank loan (note 3) 26,736 27,627

Asset retirement obligations (note 4) 17,169 14,905

Future income taxes 20,321 17,012
---------------------------------------------------------------------------
108,578 111,434

Shareholders' equity:
Share capital (note 5) 237,725 208,994
Contributed surplus (note 5) 1,307 820
Deficit (3,549) (3,884)
---------------------------------------------------------------------------
235,483 205,930

---------------------------------------------------------------------------
$344,061 $317,364
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Subsequent event (note 9)

See accompanying notes to the consolidated financial statements.



ANDERSON ENERGY LTD.

Consolidated Statements of Operations and Comprehensive Income
(unaudited)
(stated in thousands of dollars, except per share amounts)


---------------------------------------------------------------------------
---------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
2007 2006 2007 2006
----------------------------------------------------------------------------
Revenues
Oil and gas sales $18,440 $ 15,452 $38,549 $32,341
Royalties (2,967) (3,456) (7,336) (7,270)
Interest income 59 26 61 35
---------------------------------------------------------------------------
15,532 12,022 31,274 25,106
Expenses
Operating 4,417 3,772 9,310 6,920
General and administrative 1,808 1,224 3,607 2,382
Interest and other
financing charges 462 547 1,020 775
Depletion, depreciation and
accretion 8,877 10,674 17,622 20,800
---------------------------------------------------------------------------
15,564 16,217 31,559 30,877

---------------------------------------------------------------------------
Loss before taxes (32) (4,195) (285) (5,771)

Taxes
Capital taxes - (90) - -
Future income taxes
(reduction) (400) (2,430) (620) (2,900)
---------------------------------------------------------------------------
(400) (2,520) (620) (2,900)

---------------------------------------------------------------------------
Earnings (loss) for the period 368 (1,675) 335 (2,871)
Other comprehensive income
adjustments - - - -
---------------------------------------------------------------------------
Comprehensive income (loss) $ 368 $( 1,675) $ 335 $(2,871)
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Earnings (loss) per share
Basic $0.01 $ (0.03) $ 0.01 $ (0.06)
Diluted $0.01 $ (0.03) $ 0.01 $ (0.06)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.


ANDERSON ENERGY LTD.

Consolidated Statements of Deficit and Accumulated Other Comprehensive Income

(unaudited)
(stated in thousands of dollars)



---------------------------------------------------------------------------
---------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
2007 2006 2007 2006
---------------------------------------------------------------------------
Deficit, beginning of period $(3,917) $(1,546) $(3,884) $ (350)
Earnings (loss) for the period 368 (1,675) 335 (2,871)
---------------------------------------------------------------------------
Deficit, end of period $(3,549) $(3,221) $(3,549) $(3,221)
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Accumulated other comprehensive
income, beginning of period $ - $ - $ - $ -
Impact of new cash flow hedge
accounting standards (net of
tax of $695) - - 1,465 -
Reclassification to earnings of
gains on cash flow hedges - - (1,465) -
----------------------------------------------------------------------------
Accumulated other comprehensive
income, end of period $ - $ - $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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,
2007 2006 2007 2006
---------------------------------------------------------------------------
Cash provided by (used in):

Operations
Earnings (loss) for the period $ 368 $ (1,675) $ 335 $(2,871)
Items not involving cash
Depletion, depreciation and accretion 8,877 10,674 17,622 20,800
Future income taxes (reduction) (400) (2,430) (620) (2,900)
Stock-based compensation 127 159 258 303
Asset retirement expenditures (273) (188) (306) (273)
Changes in non-cash working capital
Accounts receivable and accruals (1,438) 4,318 (1,355) 5,800
Prepaid expenses and deposits 164 (655) 13 (707)
Accounts payable and accruals 1,518 (859) 1,401 (1,960)
Capital taxes payable - (288) - (184)
---------------------------------------------------------------------------
8,943 9,056 17,348 18,008
Financing
Increase (decrease) in bank loan (16,815) 11,821 (891) 25,831
Issue of common shares 32,563 148 32,563 1,729
---------------------------------------------------------------------------
15,748 11,969 31,672 27,560
Investments
Additions to property, plant and
equipment (17,649) (15,010) (45,673) (46,693)
Proceeds on sale of properties 63 1,321 806 4,459
Changes in non-cash working capital
Accounts receivable and accruals 2,735 5,876 4,883 4,781
Prepaid expenses and deposits 4 449 (98) 242
Accounts payable and accruals (9,837) (13,984) (8,939) (8,781)
---------------------------------------------------------------------------
(24,684) (21,348) (49,021) (45,992)

---------------------------------------------------------------------------
Increase (decrease) in cash 7 (323) (1) (424)
Cash, beginning of period 3 409 11 510
---------------------------------------------------------------------------
Cash, end of period $ 10 $ 86 $ 10 $ 86
---------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.

ANDERSON ENERGY LTD.

Notes to the Unaudited Interim Consolidated Financial Statements

For the six month periods ended June 30, 2007 and 2006
(tabular amounts in thousands of dollars, unless otherwise stated)

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


Anderson Energy Ltd. ("Anderson Energy" or "the Company") 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, 2006, except as disclosed in note 1. 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, 2006.

1. Change in accounting policy

On January 1, 2007, the Company adopted the new Canadian accounting standards for financial instruments - recognition and measurement, financial instruments - presentation and disclosure, hedging and comprehensive income. Prior periods have not been restated.

At January 1, 2007, the following adjustments were made to the balance sheet to adopt the new standards:



---------------------------------------------------------------------------
Increase in:
Accounts receivable - fair value of financial derivatives $ 2,160
Future income taxes 695
Accumulated other comprehensive income
Cash flow hedges, net of income taxes $ 1,465
---------------------------------------------------------------------------


The financial instruments standard established recognition and measurement criteria for financial assets, financial liabilities and financial derivatives. All financial instruments are required to be measured at fair value on initial recording except in specific circumstances. Changes in fair value in subsequent periods depends on whether the financial instrument has been classified as "held for trading", "available for sale", "held to maturity", "loans and receivables" or "other financial liabilities".

"Held for trading" financial assets and financial liabilities are measured at fair value with changes in fair value recognized in earnings. "Available for sale" financial assets are measured at fair value, with changes in fair value recognized in other comprehensive income. "Held to maturity" financial assets and "loans and receivables" and "other financial liabilities" are measured at amortized cost. The Company has classified its cash as "held for trading", its accounts receivable as "loans and receivables" and its accounts payable and long-term debt as "other financial liabilities".

The Company used financial derivatives to manage the price risk attributable to the anticipated sale of natural gas production to March 31, 2007 (see note 7). Prior to January 1, 2007, the Company applied hedge accounting to these financial derivatives. On adoption of the new standards, the Company discontinued hedge accounting for the financial derivatives held and the fair value of the financial derivatives was reflected in accumulated other comprehensive income. These net gains were subsequently reclassified to earnings as the original hedged transactions were reflected in earnings.

Prior to adoption of the new standards, physical receipt and delivery contacts were not within the scope of the definition of a financial instrument. On adoption of the new standards, the Company elected to continue to account for its commodity sales contracts and other non-financial contracts on an accrual basis rather than as non-financial derivatives.

Derivatives embedded in other financial instruments must be separated and fair valued as separate derivatives under the new standard. The Company has not identified any embedded derivatives in any of its instruments.



2. Property, plant and equipment
---------------------------------------------------------------------------
June 30, December 31,
2007 2006
---------------------------------------------------------------------------
Cost $389,722 $342,529
Less accumulated depletion and depreciation (87,401) (70,349)
---------------------------------------------------------------------------
Net book value $302,321 $272,180
---------------------------------------------------------------------------


At June 30, 2007, unproved property costs of $19.4 million (December 31, 2006 - $21.2 million) have been excluded from the full cost pool for depletion and depreciation calculations. Future development costs of proved reserves of $113.6 million (December 31, 2006 - $101.5 million) have been included for depletion, depreciation and impairment test calculations.

For the six months ended June 30, 2007, $1.6 million (June 30, 2006 - $1.5 million) of general and administrative costs were capitalized. Capitalized general and administrative costs consist of salaries, stock-based compensation and associated office rent of staff involved in capital activities.

No impairment was recognized under the ceiling test at June 30, 2007. The future commodity prices used in the ceiling test were based on commodity price forecasts adjusted for differentials specific to the reserves.

3. Bank loan

In February 2007, the Company increased its revolving credit facility with a Canadian bank, increasing the borrowing base to $75 million from $55 million. The additional $20 million in revolving credit facility is a development tranche available expressly for investments in Sylvan Lake/Edmonton Sands development. The reserves-based credit facility has a revolving period ending on July 11, 2008, extendible at the option of the lender, followed by a term period with three equal quarterly principle repayments commencing 180 days from the term date. Advances under the facility can be drawn in either Canadian or U.S. funds. The facility bears 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. 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 $31.6 million (December 31, 2006 - $27.7 million), including expected inflation of 2% per annum. The majority of the costs will be incurred between 2007 and 2019. A credit adjusted risk-free rate of 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,
2007 2006
---------------------------------------------------------------------------
Balance, beginning of period $14,905 $11,299
Liabilities incurred during period 534 3,065
Liabilities assumed on asset purchases 1,466 -
Liabilities settled in period (306) (405)
Accretion expense 570 946
---------------------------------------------------------------------------
$17,169 $14,905
---------------------------------------------------------------------------

5. Share capital and contributed surplus

Issued share capital
---------------------------------------------------------------------------
Number of
Common Amount
shares (thousands)
---------------------------------------------------------------------------
Balance at December 31, 2006 53,641,401 $208,994
Issued pursuant to prospectus 7,935,000 34,517
Share issue costs - (2,026)
Tax effect of share issue costs - 626
Stock options exercised 18,000 72
Tax effect of flow-through share renouncements - (4,458)

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

Balance at June 30, 2007 61,594,401 $237,725
---------------------------------------------------------------------------


Flow-through shares

Under flow-through share agreements entered into in 2006, the Company committed to incur $15 million of qualifying expenditures by December 31, 2007. The Company committed to use 20% of the gross proceeds to incur Canadian Exploration Expenses and 80% to incur Canadian Development Expenses. The renouncements were made on February 28, 2007 with an effective date of December 31, 2006. The Company has spent approximately $14.9 million on these expenditures to June 30, 2007.

Stock options

The Company has an employee stock option plan under which employees, directors and consultants are eligible to receive grants. Changes in the number of options outstanding during the six month period ended June 30, 2007 are as follows:



---------------------------------------------------------------------------
Balance at December 31, 2006 4,830,406
Granted 21,600
Exercised (18,000)
Expirations and cancellations (36,400)

---------------------------------------------------------------------------
Balance at June 30, 2007 4,797,606
---------------------------------------------------------------------------


The outstanding options at June 30, 2007 had an average exercise price of $4.87 per share and a weighted average remaining contractual life of 4.5 years; 3,115,873 of the options were exercisable at that date.

The fair value of the options during the period ended June 30, 2007 ranged between $1.77 to $1.99 per option (June 30, 2006 - $1.56 - $2.07 per option). The weighted average assumptions used in arriving at these values were: a risk-free interest rate of 4.0%, expected option life of 4 years, expected volatility of 50% (June 30, 2006 - 25% -30%) and a dividend yield of 0%.

Per share amounts

During the period ended June 30, 2007 there were 56,631,257 weighted average shares outstanding (June 30, 2006 - 48,693,130). On a diluted basis, there were 57,103,674 weighted average shares outstanding (June 30, 2006 - 49,702,632) after giving effect to dilutive stock options.



Contributed surplus

---------------------------------------------------------------------------
Amount
---------------------------------------------------------------------------
Balance at December 31, 2006 $820
Stock based compensation 487
---------------------------------------------------------------------------

Balance at June 30, 2007 $1,307
---------------------------------------------------------------------------

6. Cash payments

The following cash payments were made (received):

---------------------------------------------------------------------------
June 30, June 30,
2007 2006
---------------------------------------------------------------------------

Interest paid $886 $1,016
Interest received (67) (35)
Taxes paid - 304
---------------------------------------------------------------------------

7. Financial instruments

In November 2006, the Company entered into fixed price natural gas
contracts to manage commodity price risk as summarized below:

---------------------------------------------------------------------------
Natural Gas Volume/day Average Price
---------------------------------------------------------------------------
Financial Swap Contracts

January to March 2007 18,000 GJ/day $7.79/GJ
---------------------------------------------------------------------------


The gains realized to March 31, 2007 were $1.2 million and have
been included in oil and gas sales. No commodity price contracts
remained outstanding after March 31, 2007.

8. Related party transactions

At June 30, 2007, accounts payable includes $10,000 due to a company controlled by a director of the Company as a result of common joint venture interests held by the director and a company previously acquired by Anderson Energy. The transactions have been recorded under the same terms and conditions as transactions with unrelated parties.

9. Subsequent event

On July 25, 2007, the Company entered into an agreement to acquire oil and gas assets for total cash consideration of $117.1 million before closing adjustments (the "Acquisition"). Closing is expected to occur on August 31, 2007. In conjunction with the Acquisition, the Company entered into a bought deal equity financing agreement with a syndicate of underwriters. On August 13, 2007, the underwriters purchased 25.7 million subscription receipts for resale to the public at a price of $3.90 per subscription receipt for aggregate gross proceeds of $100.23 million. Each subscription receipt will entitle the holder to receive one common share of the Company upon closing of the Acquisition. In addition, the underwriters have been granted an overallotment option to purchase up to 3.855 million additional subscription receipts which may be exercised up to 30 days after closing of the offering. In conjunction with the Acquisition, the Company has negotiated an increase in its bank lines from $75 million to $105 million.



Corporate Information Contact Information
Head Office Anderson Energy Ltd.
700 Canterra Tower Brian H. Dau
400 3rd Avenue S.W. President & Chef Executive Officer
Calgary, Alberta (403) 206-6000
Canada T2P 4H2
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

Abbreviations used:
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

Contact Information

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