Anderson Energy Ltd.
TSX : AXL

Anderson Energy Ltd.

November 14, 2007 08:45 ET

Anderson Energy Ltd. Announces 2007 Third Quarter Results

CALGARY, ALBERTA--(Marketwire - Nov. 14, 2007) - Anderson Energy Ltd. ("Anderson Energy" or "the Company") (TSX:AXL) is pleased to announce its operating and financial results for the third quarter ended September 30, 2007.

Third Quarter Highlights:

- On September 1, 2007, the Company completed the acquisition of oil and natural gas assets in its core area of Greater Sylvan Lake for cash consideration of $118 million (the "Acquisition"). The Acquisition was financed through the issuance of 25.7 million common shares priced at $3.90 per share and existing credit facilities.

- AJM Petroleum Consultants have completed an interim reserves evaluation as of December 31, 2007 as a first step in the Company's annual reserves evaluation. Adjusting back to October 31, 2007, the Company's total proved reserves were 28.2 MMBOE and total proved plus probable reserves were 38.5 MMBOE, a 74% and a 54% increase respectively over the December 31, 2006 reserves. Natural gas represents 93% of the total proved and 92% of the total proved plus probable reserves.

- The Company estimates its net asset value to be $5.01 per share including the effects of the recently announced Alberta government royalty proposals (based on the assumptions described below).

- Drilling resulted in 34 gross (23.3 net) wells drilled with a success rate of 89%.

- Production averaged 5,320 BOED, 33% higher than the same period in 2006 and 20% higher than the previous quarter in 2007. Production increases were due both to acquisitions and drilling activity. Production was negatively impacted in the month of September by third party plant turnarounds and wet field conditions that delayed the tie-in of wells.

- The average natural gas price received was $5.00/Mcf, a 12% decrease from the same period in 2006 and a 31% decrease from the previous quarter in 2007.

- Funds from operations were $6.3 million ($0.09 per share), a 7% increase from the same period in 2006 and a 30% decrease from the previous quarter in 2007. The decrease from the previous quarter in 2007 is attributable to substantially lower natural gas prices and higher than anticipated operating costs.

- The Company's drilling inventory has grown to 1,229 gross (576 net) locations as of September 30, 2007. Net of wells drilled in 2007, the drilling inventory has grown 65% on a net well basis this year.

- The Company's Edmonton Sands acreage position is 314 gross (172 net) sections as of September 30, 2007. This position has grown 64% since December 31, 2006.



Financial and Operating Highlights

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

Total oil and
gas revenue $ 17,261 $ 14,651 18% $ 55,810 $ 46,992 19%

Funds from
operations $ 6,255 $ 5,873 7% $ 23,850 $ 21,205 12%
Per common
share
- basic $ 0.09 $ 0.12 (25%) $ 0.39 $ 0.43 (9%)
- diluted $ 0.09 $ 0.12 (25%) $ 0.39 $ 0.42 (7%)
Earnings (loss) $ (3,018) $ (1,509) (100%) $ (2,683) $ (4,380) 39%
Per common
share
- basic $ (0.04) $ (0.03) (33%) $ (0.04) $ (0.09) 56%
- diluted $ (0.04) $ (0.03) (33%) $ (0.04) $ (0.09) 56%

Acquisitions,
net of
dispositions $ 118,042 $ (5,295) $ 126,444 $ (486)
Other cash
capital
expenditures $ 17,924 $ 16,244 10% $ 54,389 $ 60,437 (10%)

Debt, net of
working capital $ 79,046 $ 36,159 119%

Shareholders'
equity $ 329,179 204,625 61%

Average shares
outstanding
(thousands)
Basic 70,254 49,584 42% 61,222 48,993 25%
Diluted 70,307 49,957 41% 61,276 49,977 23%

Ending shares
outstanding
(thousands) 87,294 53,588 63%

Operating (6
Mcf:1bbl
conversion)

Average daily
sales
Natural gas
(Mcfd) 26,860 19,621 37% 24,000 20,691 16%
Light/medium
crude oil (bpd) 485 585 (17%) 520 476 9%
NGL (bpd) 358 151 137% 213 158 35%
Barrels of oil
equivalent
(BOED) 5,320 4,006 33% 4,732 4,082 16%

Average sales
price
Natural gas
($/Mcf) 5.00 5.71 (12%) 6.67 6.39 4%
Light/medium
crude oil
($/bbl) 66.03 62.63 5% 59.03 60.43 (2%)
NGL ($/bbl) 59.62 60.24 (1%) 56.44 60.23 (6%)
Barrels of oil
equivalent
($/BOE) 35.29 39.41 (10%) 42.85 41.76 3%

Royalties
($/BOE) 6.68 8.31 (20%) 8.21 9.27 (11%)
Operating costs
($/BOE) 11.83 10.94 8% 11.69 9.83 19%
Operating
netbacks
($/BOE) 16.76 20.50 (18%) 23.30 23.06 1%
General and
administrative
($/BOE) 3.56 3.72 (4%) 4.14 3.37 23%
Wells drilled
(gross) 34 38 (11%) 82 92 (11%)


Production:

Third quarter production averaged 5,320 BOED, 20% higher than the previous quarter reflecting, in part, production added through acquisitions. However, there were significant plant turnarounds in September which have since been completed, which negatively impacted sales volumes on the properties acquired. As well, wet ground conditions hampered drilling and tie-in operations with only 6 Edmonton Sands net wells tied in during the quarter. The Company plans to connect for production 35 Edmonton Sands wells in the fourth quarter. Current production is estimated to be 7,000 BOED with approximately 1,100 BOED behind pipe.

The Company affirms its previously provided year end exit production guidance of 8,000 to 8,400 BOED but its average annual production may be less than previously forecast due to the factors noted above.

Operations:

During the third quarter of 2007, the Company drilled 34 gross (23.3 net) wells, 29 gross (20.1 net) were gas wells, 2 gross (0.7 net) were oil wells and 3 gross (2.5 net) were dry holes. During the quarter, the Company drilled 21 gross (18 net) Edmonton Sands gas wells. The Company also participated in 7 gross (1.5 net) Horseshoe Canyon coal bed methane wells in the quarter. Wet ground conditions in July and August reduced the size of the Edmonton Sands drilling program. However, the Company was able to drill 15 gross (13 net) Edmonton Sands wells in the month of October.

Field capital expenditures in the quarter were $17.9 million, which included $11.0 million spent on drilling and completions, and $6.6 million spent on facilities. The Company completed one of its planned large compression/pipeline projects during the quarter. It also identified an additional significant natural gas plant construction project in the Sylvan Lake area to accommodate shut-in volumes and future drilling activity. This project is expected to be completed by the third quarter of 2008.

Acquisitions/Dispositions:

On September 1, 2007, the Company completed a $118 million property acquisition and added approximately 2,100 BOED of production. The Company is very pleased with the acquisition in terms of production and reserves additions and the opportunities uncovered on the asset base. Integration is continuing with drilling operations expected to commence in the fourth quarter of 2007. The Company currently has 260 BOED of non core Eastern Alberta assets up for sale.

Alberta Royalty Review:

The Alberta government recently announced changes to the royalties payable on all Crown mineral rights owned by the province. If enacted as stated, on January 1, 2009, the impact on the Company's 2009 annual royalty would be an increase from an estimated 20.5% royalty to an estimated 21.9% royalty based on a WTI oil price of US$76.50 and an AECO natural gas price of $7.00/MCF. These estimates were prepared by AJM Petroleum Consultants as part of the interim reserves evaluation. The Company estimates that on a go forward basis, the impact of the proposed royalty changes on the Edmonton Sands drilling program will be beneficial at natural gas prices less than $7.50/MCF.

Reserves:

As was done in 2006, the Company is completing its annual reserves evaluation in two phases this year, using AJM Petroleum Consultants. The industry is short of qualified reserves evaluation professionals that work for independent engineering firms. Therefore, the Company elected to complete an interim reserves evaluation that reflected a thorough reserves review of all of the Company's properties with information available as of October 31, 2007. The interim reserves evaluation incorporates reserves additions and revisions for the first ten months of the year. The reserves report was prepared with an effective date of December 31, 2007 and estimated production for November and December were added back to determine the October 31, 2007 reserve estimates. The first phase is not the Company's annual reserves report. The Company will be completing its annual reserves evaluation in early March 2008, which will include a review of activity and performance of the Company's properties for the last two months of the year, updated with a December 31, 2007 price forecast. At that time, the Company will be making the customary annual reserves information filings as part of the year end reporting process.

Adjusting to October 31, 2007, the Company's total proved reserves are 28.2 MMBOE and total proved plus probable reserves are 38.5 MMBOE, a 74% and a 54% increase respectively over December 31, 2006 reserves. Natural gas represents 93% of the total proved and 92% of the total proved plus probable reserves. Natural gas liquids represent 5.3% and 5.5% of the total proved and total proved plus probable reserves.

Based on the interim reserves evaluation effective December 31, 2007, the Company estimates its net asset value to be $5.01 per share, using AJM Petroleum Consultants September 30, 2007 price forecast. This estimate uses a pretax 10% discount rate net present value for proved plus probable reserves and includes the proposed changes to the Alberta Crown royalties. The estimate assumes a $20 million value for undeveloped land and 2007 year end debt levels based on budgeted capital expenditures, and is based on 87.3 million common shares outstanding. When the Company releases its year end results and completes an independent appraisal of its undeveloped land, a revised net asset value per share estimate will be prepared incorporating a year end price forecast.

Outlook:

The Company's net well drilling inventory has grown 65% since the start of the year. The Company's net Edmonton Sands lands position has grown 64% since the start of the year.

Canadian 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 heading into the winter and a strong Canadian dollar. US natural gas storage levels are 2.9% higher than levels seen last year and 8.9% higher than five year averages. US storage levels are high due to increased LNG imports into the United States and natural gas demand associated with air conditioning being lower than last year due to cooler than normal temperatures in the southern United States. Over time, the reduction in Canadian natural gas drilling activity due to lower natural gas prices, the potential reaction from the recent Alberta royalty changes and an 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 could also have a positive impact on prices in the balance of this year and in 2008.

In the balance of the year, the Company will be integrating its recent acquisition, adding to its opportunity base through additional Edmonton Sands farm-ins and selectively evaluating potential property acquisitions.

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
November 14, 2007


Anderson Energy Ltd.
Management's Discussion and Analysis for the Nine Months Ended
September 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 nine months ended September 30, 2007 and 2006 and is based on information available as of November 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:

On September 1, 2007, the Company completed an acquisition of oil and natural gas assets in its core area of Greater Sylvan Lake for cash consideration of $118 million (the "Acquisition"). Production from the Acquisition is approximately 2,100 BOED of which 75% is natural gas. The Acquisition was financed through the issuance of 25.7 million common shares at $3.90 per share under a bought deal financing and existing credit facilities. The Company now has 87.3 million common shares outstanding.

Sales volumes for the three months ended September 30, 2007 were 5,320 BOED, which was a 20% increase over the second quarter of 2007. The increase was largely due to additional production added through acquisitions.

Funds from operations were $6.3 million or $0.09 per share in the quarter, 30% lower than the second quarter of 2007. The impact of lower gas prices and higher expenses offset the impact of the production increases. Capital expenditures were $136.0 million during the third quarter of 2007, including the Acquisition. The result was an overall increase in debt, net of working capital to $79.0 million at September 30, 2007. The Company increased its credit facilities from $75 million to $105 million in the quarter.

Revenue and Production:

Production for the three months ended September 30, 2007 was 5,320 BOED, 20% higher than the second quarter of 2007 and 33% higher than the 4,006 BOED sold in the corresponding period of 2006. The volumes reflect additional production from a $9.2 million property acquisition completed on June 29, 2007 and the $118 million Acquisition completed on September 1, 2007. These increases were offset to some extent by third party plant turnarounds on the recently acquired properties and well tie-in delays due to wet ground conditions in and around the Edmonton Sands core area of operations. For the nine months ended September 30, 2007, production increased 16% to 4,732 BOED from 4,082 BOED in the corresponding period of 2006.

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



Three months ended Nine months ended
September 30 September 30
----------------------------------------
Oil and Natural Gas Revenue 2007 2006 2007 2006
(thousands of dollars)
Natural gas $ 12,361 $ 10,316 $ 42,557 $ 36,090
Natural gas hedging gains - - 1,157 -
Oil 2,947 3,373 8,376 7,855
NGL 1,963 836 3,274 2,593
Royalty and other (10) 126 446 454
----------------------------------------------------------------------------
Total $ 17,261 $ 14,651 $ 55,810 $ 46,992
----------------------------------------------------------------------------

Production
Natural gas (Mcfd) 26,860 19,621 24,000 20,691
Oil (bpd) 485 585 520 476
NGL (bpd) 358 151 213 158
----------------------------------------------------------------------------
Total (BOED) 5,320 4,006 4,732 4,082
----------------------------------------------------------------------------

Prices
Natural gas ($/Mcf) $ 5.00 $ 5.71 $ 6.67 $ 6.39
Oil ($/bbl) 66.03 62.63 59.03 60.43
NGL ($/bbl) 59.62 60.24 56.44 60.23
Total ($/BOE) $ 35.29 $ 39.41 $ 42.85 $ 41.76


Natural gas comprised 84% of total production at 26.9 MMcfd in the third quarter of 2007, an increase from 22.9 MMcfd in the second quarter of 2007 and 19.6 MMcfd in the third quarter of 2006. Oil production averaged 485 bpd in the third quarter of 2007 compared to 504 bpd in the second quarter of 2007 and 585 bpd in the third quarter of 2006. Natural gas liquids production averaged 358 bpd in the third quarter of 2007 compared to 98 bpd in the second quarter of 2007 and 151 bpd in the third quarter of 2006.

Lower natural gas prices had a significant impact on third quarter revenue. Anderson Energy's average natural gas price was $5.00/Mcf for the three months ended September 30, 2007, lower than the $7.25/Mcf realized in the second quarter of 2007 and lower than the $5.71/Mcf realized in the third quarter of 2006. For the nine months ended September 30, 2007, realized natural gas prices were $6.67/Mcf, 4% higher than the $6.39/Mcf realized in the same period of 2006. The natural gas price in the first nine months of 2007 includes hedging gains of $1.2 million. The 2007 year-to-date gas price before hedging gains was $6.50/Mcf. Royalty revenue adjustments were booked in the third quarter of 2007 which affected prior quarters.

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

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 $3.3 million (19% of revenue) in the third quarter of 2007 higher than the second quarter of 2007 and slightly lower than the third quarter of 2006. Royalties in the second quarter of 2007 were reduced by assessments related to 2006 gas cost allowance. For the nine months ended September 30, 2007, royalties were $10.6 million (19% of revenue), compared to $10.3 million (22% of revenue) in the corresponding period of 2006. In 2006, the Company received Alberta Royalty Tax Credits of $500,000. This program has been discontinued in 2007. The Company expects 2007 royalties to increase overall as production increases, but the average royalty rate as a percentage of revenue should be similar to current levels for the remainder of the year. On October 25, 2007, the Alberta government announced proposed changes to the Crown royalty system. These changes are expected to come into effect on January 1, 2009 and are discussed in further detail under Business Risks.

Operating Expenses:

Operating expenses were $11.83/BOE ($5.8 million) in the third quarter, 8% higher than the $10.97/BOE recorded in the second quarter of 2007 and the $10.94/BOE recorded in the third quarter of 2006. Some prior period charges for fuel costs and third party gas processing adjustments going back to 2005 were recorded in the period. For the nine months ended September 30, 2007, operating costs were $11.69/BOE ($15.1 million), 19% higher than the $9.83/BOE ($11.0 million) recorded in the corresponding period of 2006. In addition to overall increases in costs, year to date operating costs were impacted by a series of workovers, pump changes and compressor repairs as well as third party 2005 and 2006 gas processing adjustments. Various shut-ins, including the shut-in at Chinchaga in the first quarter, also increased operating costs on a BOE basis.



Operating Netback:

Three months ended Nine months ended
September 30 September 30
----------------------------------------
2007 2006 2007 2006
(thousands of dollars)
Revenue $ 17,261 $ 14,651 $ 55,810 $ 46,992
Royalties (3,270) (3,064) (10,606) (10,334)
Operating expenses (5,788) (4,031) (15,098) (10,951)
----------------------------------------
$ 8,203 $ 7,556 $ 30,106 $ 25,707
----------------------------------------

Sales (MBOE) 489.4 368.6 1,291.9 1,114.5

($/BOE)
Revenue $ 35.27 $ 39.75 $ 43.20 $ 42.16
Royalties (6.68) (8.31) (8.21) (9.27)
Operating expenses (11.83) (10.94) (11.69) (9.83)
----------------------------------------
$ 16.76 $ 20.50 $ 23.30 $ 23.06
----------------------------------------
----------------------------------------


General and Administrative Expenses:

General and administrative expenses ("G&A") consist largely of salaries, rent, computer software and other office costs. G&A expenses were $3.56/BOE ($1.7 million) in the third quarter of 2007, 21% lower than the $4.49/BOE in the second quarter of 2007 and 4% lower than the $3.72/BOE ($1.4 million) recorded in the third quarter of 2006. For the nine months ended September 30, 2007, G&A costs were $4.14/BOE ($5.3 million), 23% higher than the $3.37/BOE ($3.8 million) incurred in the same period of 2006. On a BOE basis, G&A costs decreased in the third quarter due to increased production and we expect this trend to continue.



Three months ended Nine months ended
September 30 September 30
----------------------------------------
2007 2006 2007 2006
General and administrative (gross) $ 2,857 $ 2,463 $ 8,794 $ 7,484
Overhead recoveries (326) (411) (1,055) (1,523)
Capitalized (790) (683) (2,391) (2,210)
----------------------------------------
General and administrative (net) $ 1,741 $ 1,369 $ 5,348 $ 3,751
----------------------------------------------------------------------------

General and administrative ($/BOE) $ 3.56 $ 3.72 $ 4.14 $ 3.37

% G&A capitalized 28% 28% 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 $0.6 million in the third quarter, higher than the $0.5 million in the second quarter of 2007 due to increased debt levels associated with the Acquisition. For the nine months ended September 30, 2007, interest expense was $1.6 million, 24% higher than the $1.3 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 $20.75 ($10.2 million) in the third quarter, lower than the $21.31 ($8.6 million) recorded in the second quarter of 2007 and lower than the $21.62 ($8.0 million) recorded in the third quarter of 2006. For the nine months ended September 30, 2007, depletion and depreciation per BOE decreased 17% to $21.06 ($27.2 million) compared to $25.42 ($28.3 million) recorded in the corresponding period of 2006. Depletion and depreciation expense is calculated using proved reserves only and the decrease 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:

The Company recorded $6.5 million in asset retirement obligations in the third quarter of 2007, compared to $1.7 million in the second quarter of 2007 and $0.6 million in the third quarter of 2006. Asset retirement obligations associated with the Acquisition completed in the third quarter were $5.9 million. Asset retirement obligations associated with the acquisition completed in the second quarter were $1.5 million. Accretion expense was $0.4 million for the third quarter of 2007, $0.3 million for the second quarter of 2007 and $0.2 million in the third quarter of 2006 and is included in depletion, depreciation and accretion expense.

Income Taxes:

The Company is not currently taxable. The Company has approximately $257 million in available tax pools as of September 30, 2007.

In the third quarter, the Company recorded a $1.4 million future income tax recovery, compared to a $1.0 million recovery in the corresponding period in 2006. For the nine months ended September 30, 2007, the future income tax recovery was $2.0 million compared to a $3.9 million recovery in the same period of 2006.

The federal government announced further future corporate tax reductions on October 31, 2007. The effect of these reductions has not yet been reflected in future income taxes.

Funds from Operations:

Funds from operations for the three months ended September 30, 3007 were $6.3 million, compared to $9.0 million in the second quarter of 2007 and $5.9 million in the third quarter of 2006. On a per share basis, funds from operations were $0.09 for the third quarter of 2007, $0.15 for the second quarter of 2007 and $0.12 for the third quarter of 2006. Funds from operations in the third quarter were significantly affected by depressed gas prices. For the nine months ended September 30, 2007, funds from operations were $23.9 million compared to $21.2 million in the corresponding period in 2006. Higher funds from operations are the result of higher production volumes, offset to some extent by higher costs.

Earnings:

The Company reported a net loss of $3.0 million for the three months ended September 30, 2007, compared to earnings of $0.4 million in the second quarter of 2007 and a loss of $1.5 million in the third quarter of 2006. For the nine months ended September 30, 2007, the Company recorded a net loss of $2.7 million compared to a loss of $4.4 million in the same period in 2006.

Capital Expenditures:

The Company spent $180.8 million in cash capital expenditures in the first nine months of 2007, of which $136.0 million was spent in the third quarter. The breakdown of capital additions is shown below:



(thousands of dollars) Three months ended Nine months ended
September 30, 2007 September 30, 2007
---------------------------------------

Land, geological & geophysical costs $ 202 $ 2,046
Acquisitions, net of dispositions 118,042 126,444
Drilling, completion and
recompletion 10,995 24,676
Facilities and well equipment 6,602 23,586
Capitalized G&A 657 2,029
---------------------------------------
Total finding and development
expenditures 136,498 178,781
Compressor and other equipment
inventory (544) 1,972
Office equipment and furniture 12 80
---------------------------------------
Total cash capital expenditures $ 135,966 $ 180,833
Non-cash asset retirement
obligations and capitalized
stock based compensation 750 2,979
---------------------------------------
Total cash and non-cash capital
additions $ 136,716 $ 183,812
---------------------------------------

Drilling statistics are shown below:

Three months ended Nine months ended
September 30 September 30
------------------------- ---------------------------
2007 2006 2007 2006
Gross Net Gross Net Gross Net Gross Net

Gas 29.0 20.1 35.0 15.6 69.0 45.8 79.0 35.9
Oil 2.0 0.7 - - 5.0 2.2 6.0 4.0
Dry 3.0 2.5 3.0 2.1 8.0 4.7 7.0 5.3
------------------------- ---------------------------
Total 34.0 23.3 38.0 17.7 82.0 52.7 92.0 45.2
------------------------- ---------------------------

Success rate (%) 91% 89% 92% 88% 90% 91% 92% 88%


In the third quarter of 2007, 21 gross Edmonton Sands gas wells and 7 Horseshoe Canyon coal bed methane wells were drilled.

On September 1, 2007, the Company completed the acquisition of oil and natural gas assets in the Strachan and Pembina areas of Alberta for aggregate cash consideration of $118 million.

The Company estimates it will spend $200 to $205 million in 2007, assuming the Eastern Alberta property sale is closed by year end.

Liquidity and Capital Resources:

Early in 2007, the Company increased its bank loan facility from $55 million to $75 million. On September 4, 2007, the Company increased its bank loan facility again to $105 million, in conjunction with the Acquisition. The new facilities include a $95 million extendible, revolving term credit facility and a $10 million working capital credit facility arranged with a small syndicate of Canadian banks.

As of September 30, 2007, total long term debt plus net working capital deficiency was $79.0 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 31, 2007, the Company issued 25,700,000 common shares at a price of $3.90 per share for gross proceeds of $100.2 million ($94.7 million after commission and expenses) in conjunction with the Acquisition.

As of November 13, 2007, there are 87.3 million common shares outstanding and 6.3 million stock options outstanding.

Contractual Obligations:

On February 28, 2007, the Company renounced $15 million of qualifying expenditures under flow through share agreements entered into in 2006. As of September 30, 2007, the Company has incurred all of the qualifying expenditures under the commitment.

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 nine months ended September 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 coal bed methane, would be conducted by a panel of experts with the assistance of individual Albertans and key stakeholders. The review panel published a final report on September 18, 2007. On October 25, 2007, the Alberta government announced their response to the review panel's report. The proposed changes to the Alberta Crown royalty system 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 current 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 are paid to the Alberta Crown and as such are affected by the changes.

Business Prospects:

The Company has an excellent drilling inventory with over 6 to 8 years of development drilling locations in its three core resource plays, Sylvan Lake Edmonton Sands, Horseshoe Canyon Coal Bed Methane and northeast B.C. In the balance of the year, the Company is planning to drill approximately 45 Edmonton Sands 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 will be reviewing its 2008 capital program on December 13, 2007 and will provide appropriate guidance shortly thereafter.

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 Alberta. The Company will likely continue to consolidate its land holdings and conduct further dispositions.



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

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

Oil & gas revenue before royalties $ 17,261 $ 18,440 $ 20,109 $ 16,820
Funds from operations $ 6,255 $ 8,972 $ 8,623 $ 7,996
Funds from operations per share
Basic $ 0.09 $ 0.15 $ 0.16 $ 0.15
Diluted $ 0.09 $ 0.15 $ 0.16 $ 0.15
Earnings (loss) $ (3,018) $ 368 $ (33) $ 846
Earnings (loss) per share
Basic $ (0.04) $ 0.01 $ - $ 0.02
Diluted $ (0.04) $ 0.01 $ - $ 0.02
Capital expenditures, including
acquisitions $ 135,966 $ 17,586 $ 27,281 $ 20,662
Daily sales
Natural gas (Mcfd) 26,860 22,928 22,162 21,075
Liquids (bpd) 843 602 750 692
BOE (bpd) 5,320 4,423 4,444 4,205
Average prices
Natural gas ($/Mcf) $ 5.00 $ 7.25 $ 8.14 $ 6.82
Liquids ($/bbl) $ 63.31 $ 58.18 $ 52.59 $ 51.09
BOE ($/BOE) $ 35.29 $ 45.49 $ 49.45 $ 42.62

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

Oil & gas revenue before royalties $ 14,651 $ 15,452 $ 16,889 $ 22,894
Funds from operations $ 5,873 $ 6,728 $ 8,604 $ 13,187
Funds from operations per share
Basic $ 0.12 $ 0.14 $ 0.18 $ 0.28
Diluted $ 0.12 $ 0.13 $ 0.17 $ 0.27
Earnings (loss) $ (1,509) $ (1,675) $ (1,196) $ 1,762
Earnings (loss) per share
Basic $ (0.03) $ (0.03) $ (0.02) $ 0.04
Diluted $ (0.03) $ (0.03) $ (0.02) $ 0.04
Capital expenditures, including
acquisitions $ 10,949 $ 15,994 $ 33,008 $ 24,535
Daily sales
Natural gas (Mcfd) 19,621 21,664 20,799 18,785
Liquids (bpd) 736 549 614 577
BOE (bpd) 4,006 4,160 4,081 3,708
Average prices
Natural gas ($/Mcf) $ 5.71 $ 6.05 $ 7.40 $ 11.39
Liquids ($/bbl) $ 62.14 $ 68.19 $ 51.15 $ 53.56
BOE ($/BOE) $ 39.41 $ 40.50 $ 45.41 $ 66.05


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, value of undeveloped land 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 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.

RELOCATION:

On November 26, 2007, the Company will be relocating its offices to 700 Selkirk House, 555 4th Avenue SW, Calgary, Alberta T2P 3E7. Our telephone and fax numbers will remain the same.





ANDERSON ENERGY LTD.
Consolidated Balance Sheets
(unaudited)
(stated in thousands of dollars)

----------------------------------------------------------------------------
----------------------------------------------------------------------------
September 30, December 31,
2007 2006
----------------------------------------------------------------------------

Assets

Current assets:
Cash $ 1 $ 11
Accounts receivable and accruals 27,954 28,885
Prepaid expenses and deposits 3,042 1,968
----------------------------------------------------------------------------
30,997 30,864

Property, plant and equipment (note 3) 444,420 272,180

Goodwill (note 2) 35,364 14,320

----------------------------------------------------------------------------
$510,781 $317,364
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities and Shareholders' Equity

Current liabilities:
Accounts payable and accruals $ 53,953 $ 51,890

Bank loans (note 4) 56,090 27,627

Asset retirement obligations (note 5) 23,681 14,905

Future income taxes 47,878 17,012
----------------------------------------------------------------------------
181,602 111,434
Shareholders' equity:
Share capital (note 6) 334,147 208,994
Contributed surplus (note 6) 1,599 820
Deficit (6,567) (3,884)
----------------------------------------------------------------------------
329,179 205,930

----------------------------------------------------------------------------
$510,781 $317,364
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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 Nine months ended
September 30, September 30,
2007 2006 2007 2006
----------------------------------------------------------------------------

Revenues
Oil and gas sales $17,261 $14,651 $55,810 $46,992
Royalties (3,270) (3,064) (10,606) (10,334)
Interest income 224 38 285 73
----------------------------------------------------------------------------
14,215 11,625 45,489 36,731
Expenses
Operating 5,788 4,031 15,098 10,951
General and administrative 1,741 1,369 5,348 3,751
Interest and other financing charges 589 522 1,609 1,297
Depletion, depreciation and
accretion 10,515 8,212 28,137 29,012
----------------------------------------------------------------------------
18,633 14,134 50,192 45,011

----------------------------------------------------------------------------
Loss before taxes (4,418) (2,509) (4,703) (8,280)

Taxes
Future income tax reduction (1,400) (1,000) (2,020) (3,900)
----------------------------------------------------------------------------
(1,400) (1,000) (2,020) (3,900)
----------------------------------------------------------------------------

Loss for the period (3,018) (1,509) (2,683) (4,380)
Other comprehensive income
adjustments - - - -
----------------------------------------------------------------------------
Comprehensive income (loss) $(3,018) $(1,509) $(2,683) $(4,380)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Loss per share
Basic $ (0.04) $ (0.03) $ (0.04) $ (0.09)
Diluted $ (0.04) $ (0.03) $ (0.04) $ (0.09)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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 Nine months ended
September 30, September 30,
2007 2006 2007 2006
----------------------------------------------------------------------------

Deficit, beginning of period $(3,549) $(3,221) $(3,884) $ (350)
Loss for the period (3,018) (1,509) (2,683) (4,380)
----------------------------------------------------------------------------
Deficit, end of period $(6,567) $(4,730) $(6,567) $(4,730)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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 Nine months ended
September 30, September 30,
2007 2006 2007 2006
----------------------------------------------------------------------------

Cash provided by (used in):

Operations
Loss for the period $ (3,018) $ (1,509) $ (2,683) $(4,380)
Items not involving cash
Depletion, depreciation and
accretion 10,515 8,212 28,137 29,012
Future income tax reduction (1,400) (1,000) (2,020) (3,900)
Stock-based compensation 158 170 416 473
Asset retirement expenditures (386) (90) (692) (363)
Changes in non-cash working
capital
Accounts receivable and accruals 384 (874) (971) 4,926
Prepaid expenses and deposits (968) 69 (955) (638)
Accounts payable and accruals 516 894 1,917 (1,066)
Capital taxes payable - - - (184)
----------------------------------------------------------------------------
5,801 5,872 23,149 23,880

Financing
Increase (decrease) in bank loan 29,354 (12,115) 28,463 13,716
Issue of common shares 94,719 19,050 127,282 20,779
----------------------------------------------------------------------------
124,073 6,935 155,745 34,495

Investments
Additions to property, plant and
equipment (17,963) (16,236) (63,636) (62,929)
Acquisition of 3210700 Nova Scotia
Company (note 2) (117,634) - (117,634) -
Payment of liabilities assumed on
acquisition (note 2) (324) - (324) -
Proceeds on sale of properties (45) 5,287 761 9,746
Changes in non-cash working
capital
Accounts receivable and accruals (2,981) 228 1,902 5,009
Prepaid expenses and deposits (21) 149 (119) 391
Accounts payable and accruals 9,085 (2,302) 146 (11,083)
----------------------------------------------------------------------------
(129,883) (12,874) (178,904) (58,866)

----------------------------------------------------------------------------
Decrease in cash (9) (67) (10) (491)

Cash, beginning of period 10 86 11 510
----------------------------------------------------------------------------

Cash, end of period $ 1 $ 19 $ 1 $ 19
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.



ANDERSON ENERGY LTD.

Notes to the Unaudited Interim Consolidated Financial Statements

For the nine month periods ended September 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 8). 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. Acquisition

On September 1, 2007, the Company completed the acquisition of certain oil and natural gas assets located in the Strachan area in Central Alberta and the Pembina area in North Central Alberta (the "Assets") (indirectly through the purchase of all of the issued and outstanding shares of a newly formed company, 3210700 Nova Scotia Company) for aggregate cash consideration of $117,131,000 ($117,634,000 after adjustments and expenses). The acquisition has been accounted for using the purchase method of accounting. The purchase price has been allocated as follows:



Net Assets at Assigned Values ($000s)
----------------------------------------------------------------------------
Property, plant and equipment $133,441
Deposits 241
Goodwill 21,044
Future income taxes (30,604)
Provision for loss on transportation contracts (565)
Asset retirement obligation (5,923)
----------------------------------------------------------------------------
$117,634
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Consideration
----------------------------------------------------------------------------
Cash $117,234
Acquisition costs 400
----------------------------------------------------------------------------
Total purchase price $117,634
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The purchase price after adjustments is an estimate made by management based on information currently available. The estimate is subject to change as the adjustment amounts are finalized with the vendor.



3. Property, plant and equipment

----------------------------------------------------------------------------
----------------------------------------------------------------------------
September 30, December 31,
2007 2006
----------------------------------------------------------------------------
Cost $541,977 $342,529
Less accumulated depletion and
depreciation (97,557) (70,349)
----------------------------------------------------------------------------
Net book value $444,420 $272,180
----------------------------------------------------------------------------
----------------------------------------------------------------------------


At September 30, 2007, unproved property costs of $20.4 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 $188.8 million (December 31, 2006 - $101.5 million) have been included for depletion, depreciation and impairment test calculations.

For the nine months ended September 30, 2007, $2.4 million (September 30, 2006 - $2.2 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 September 30, 2007. The future commodity prices used in the ceiling test were based on commodity price forecasts adjusted for differentials specific to the reserves.

4. Bank loans

On September 4, 2007, the Company entered into 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 15, 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 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. Loans are secured by a floating charge debenture over all assets and guarantees by material subsidiaries.

5. Asset retirement obligations

The Company estimates the total undiscounted cash flows required to settle its asset retirement obligations is approximately $50.6 million (December 31, 2006 - $27.7 million), including expected inflation of 2% per annum. The majority of the costs will be incurred between 2008 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:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
September 30, December 31,
2007 2006
----------------------------------------------------------------------------
Balance, beginning of period $14,905 $11,299
Liabilities incurred during period 1,150 3,065
Liabilities assumed on asset purchases 7,389 -
Liabilities settled in period (692) (405)
Accretion expense 929 946
----------------------------------------------------------------------------
$23,681 $14,905
----------------------------------------------------------------------------
----------------------------------------------------------------------------

6. 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 prospectuses 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 share
renouncements - (4,458)

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

Balance at September 30, 2007 87,294,401 $334,147
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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. As of September 30, 2007, the Company has incurred all of the qualifying expenditures.

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 nine month period ended September 30, 2007 are as follows:



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

Balance at December 31, 2006 4,830,406
Granted 1,476,000
Exercised (18,000)
Expirations and cancellations (43,200)

----------------------------------------------------------------------------
Balance at September 30, 2007 6,245,206
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The outstanding options at September 30, 2007 had an average exercise price of $4.66 per share and a weighted average remaining contractual life of 4.4 years; 3,436,539 of the options were exercisable at that date.

The fair value of the options during the period ended September 30, 2007 ranged between $1.59 to $1.99 per option (September 30, 2006 - $1.51 - $2.07 per option). The weighted average assumptions used in arriving at these values were: a risk-free interest rate of 4.0% to 4.4% (September 30, 2006 - 3.9% to 4.5%), expected option life of 4 years, expected volatility of 40% to 50% (September 30, 2006 - 25% - 35%) and a dividend yield of 0%.

Per share amounts

During the period ended September 30, 2007 there were 61,222,134 weighted average shares outstanding (September 30, 2006 - 48,993,371). On a diluted basis, there were 61,275,528 weighted average shares outstanding (September 30, 2006 - 49,977,007) after giving effect to dilutive stock options.



Contributed surplus

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Amount
----------------------------------------------------------------------------
Balance at December 31, 2006 $ 820
Stock based compensation 779
----------------------------------------------------------------------------

Balance at September 30, 2007 $1,599
----------------------------------------------------------------------------
----------------------------------------------------------------------------

7. Cash payments

The following cash payments were made (received):

----------------------------------------------------------------------------
----------------------------------------------------------------------------
September 30, September 30,
2007 2006
----------------------------------------------------------------------------

Interest paid $1,864 $1,218
Interest received (290) (73)
Taxes paid - 304
----------------------------------------------------------------------------
----------------------------------------------------------------------------


8. 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.

9. Related party transactions

In August 2007, the Company issued 344,494 common shares to directors and officers of the Company at a price of $3.90 per share for total proceeds of $1.3 million as part of a $100.2 million public offering of common shares.

At September 30, 2007, accounts payable includes $1,000 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.



Corporate Information Contact Information

Head Office Anderson Energy Ltd.
700 Canterra Tower Brian H. Dau
400 3(rd) 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