Anderson Energy Ltd.
TSX : AXL

Anderson Energy Ltd.

November 13, 2006 18:51 ET

Anderson Energy Ltd. Announces Third Quarter 2006 Results

CALGARY, ALBERTA--(CCNMatthews - Nov. 13, 2006) - Anderson Energy Ltd. (TSX:AXL) ("Anderson Energy" or "the Company") is pleased to announce its operating and financial results for the third quarter ended September 30, 2006.

Highlights:

- AJM Petroleum Consultants has completed an interim reserves evaluation as a first step in the Company's annual reserves evaluation. Effective October 31, 2006, the Company's total proved reserves are 14.7 MMBOE and total proved plus probable reserves are 23.2 MMBOE, 53% and 27% increases over December 31, 2005 reserves respectively. Natural gas represents 94% of the total proved and total proved plus probable reserves.

- On September 25, the Company completed $20 million in gross equity financings ($19 million net of commission and expenses), with a total of 4.28 million shares issued. The funds were raised through a $15 million flow through public share offering and a $5 million private placement. Directors and officers of the Company purchased $6.2 million of the financings.

- Third quarter production averaged 4,006 BOED, a 78% increase over the comparable quarter in 2005. Third quarter production declined 4% over the second quarter of 2006 and was negatively impacted by the Sylvan Lake gas plant and fire which occurred on July 4. Production was restored to pre-incident production levels on August 29. Current production is approximately 4,600 BOED and behind pipe production capacity awaiting tie-in is approximately 1,200 BOED.

- As of September 30, 2006, the Company's drilling inventory is approximately 956 gross (392 net) wells. The Edmonton Sands play represents 75% of the net inventory and Horseshoe Canyon coal bed methane projects represent 15% of the net inventory.

- The Company has added 46 gross (35 net) sections of Edmonton Sands land through land acquisitions and farm in deals, a 50% net increase since December 31, 2005.

- Drilling for the three months ended September 30, 2006 resulted in 38 gross (17.7 net) wells drilled with a success rate of 92%.

- The average natural gas price for the third quarter was $5.71/Mcf which is $3.97/Mcf lower than the comparable quarter in 2005 and $0.34/Mcf lower than the second quarter of 2006.

- Cash flow from operations in the third quarter of 2006 is $5.9 million or $0.12 per share, a decrease of $0.9 million over both the comparable quarter in 2005 and the second quarter of 2006.



Financial and Operating Highlights

Three months ended %
September 30 Change
--------------------
2006 2005
--------------------
Financial
(thousands of dollars, except share data)

Total oil and gas revenue $ 14,651 $ 12,147 21%

Cash flow from operations $ 5,873 $ 6,746 (13%)
Per common share - basic $ 0.12 $ 0.18 (33%)
- diluted $ 0.12 $ 0.17 (29%)

Earnings (loss) (1,509) 543 (378%)
Per common share - basic $ (0.03) $ 0.01 (400%)
- diluted $ (0.03) $ 0.01 (400%)

Capital expenditures 11,592 14,960 (23%)
Debt, net of working capital

Shareholders' equity

Average shares outstanding (thousands)
Basic 49,584 38,224 30%
Diluted 49,957 39,132 28%

Ending shares outstanding (thousands)

Operating (6 Mcf:1bbl conversion)

Average daily sales
Natural gas (Mcfd) 19,621 11,991 64%
Light/medium crude oil (bpd) 585 181 223%
NGL (bpd) 151 69 119%
Barrels of oil equivalent (BOED) 4,006 2,249 78%

Average sales price
Natural gas ($/Mcf) 5.71 9.68 (41%)
Light/medium crude oil ($/bbl) 62.63 62.06 1%
NGL ($/bbl) 60.24 62.94 (4%)
Barrels of oil equivalent ($/BOE) 39.41 58.49 (33%)


Royalties ($/BOE) 8.31 11.73 (29%)
Operating costs ($/BOE) 10.94 9.77 12%
Operating netbacks ($/BOE) 20.50 37.19 (45%)
General and administrative ($/BOE) 3.72 4.39 (15%)

Wells drilled (gross) 38 32 19%


Nine months ended %
September 30 Change
--------------------
2006 2005
--------------------
Financial
(thousands of dollars, except share data)

Total oil and gas revenue $ 46,992 $ 24,059 95%

Cash flow from operations $ 21,205 $ 12,268 73%
Per common share - basic $ 0.43 $ 0.35 23%
- diluted $ 0.42 $ 0.34 24%

Earnings (loss) (4,380) (1,031) (325%)
Per common share - basic $ (0.09) $ (0.03) (200%)
- diluted $ (0.09) $ (0.03) (200%)

Capital expenditures 61,965 47,095 32%
Debt, net of working capital 36,159 13,539 (167%)

Shareholders' equity 204,625 181,348 13%

Average shares outstanding (thousands)
Basic 48,993 35,160 39%
Diluted 49,977 36,073 39%

Ending shares outstanding (thousands) 53,588 47,806 12%

Operating (6 Mcf:1bbl conversion)

Average daily sales
Natural gas (Mcfd) 20,691 9,940 108%
Light/medium crude oil (bpd) 476 68 600%
NGL (bpd) 158 42 276%
Barrels of oil equivalent (BOED) 4,082 1,767 131%

Average sales price
Natural gas ($/Mcf) 6.39 8.17 (22%)
Light/medium crude oil ($/bbl) 60.43 61.58 (2%)
NGL ($/bbl) 60.23 58.28 3%
Barrels of oil equivalent ($/BOE) 41.76 49.68 (16%)

Royalties ($/BOE) 9.27 9.90 (6%)
Operating costs ($/BOE) 9.83 9.52 3%
Operating netbacks ($/BOE) 23.06 30.46 (24%)
General and administrative ($/BOE) 3.37 5.27 (36%)

Wells drilled (gross) 92 69 33%


Production:

Early in the third quarter, there was an explosion and fire at the Focus Energy Trust Sylvan Lake Gas Plant. This impacted approximately 5.9 Mmcfd of the Company's production that is custom processed at this gas plant. As of August 29, 2006, the Company has managed to restore production volumes to pre-incident levels through an undamaged portion of the Sylvan Lake Gas plant and through other gas processing facilities in the immediate area. Shortly after the incident, the Company suspended all of its drilling, completion and well tie-in operations in the vicinity of the Sylvan Lake gas plant. All of the capital spending activities resumed late in the third quarter. Current production is approximately 4,600 BOED and behind pipe production capacity awaiting tie-in is approximately 1,200 BOED.

Operations:

In the third quarter, the Company spent $11.6 million in capital, including dispositions of $5.3 million. The Company drilled 38 gross (17.7 net) wells with a success rate of 92%.

In the Sylvan Lake area, the Company drilled 21 gross (13.2 net) Edmonton Sands gas wells. In other areas, the Company drilled 13 gross (2 net) CBM wells in the Ghost Pine area and two gross (1.4 net) CBM dry holes to evaluate its southern Alberta land blocks. The Company also drilled a 50% working interest gas well in the Pembina area.

Acquisitions and Dispositions:

As of November 13, 2006, the Company has completed seven property acquisition transactions by issuing 943,791 common shares worth $6.8 million as consideration. Five of the transactions were producing property acquisitions where the Company acquired a partner minority interest in petroleum and natural gas assets in the former Aquest properties. The other two transactions were undeveloped land acquisitions in the Ghost Pine CBM project area. Two additional deals were done for cash totaling $2.5 million to acquire production and/or undeveloped land in the Sylvan Lake area.

As of September 30, 2006, the Company had sold $9.7 million in properties and, on October 18, 2006, the Company sold an additional property for $2.6 million for a total of $12.3 million in dispositions (as of November 13, 2006). Total estimated production sold is 120 BOED.

Equity Issue:

On September 25, 2006, the Company completed $20 million in equity financings. The Company raised $15 million by issuing CDE/CEE flow though shares at $4.70 per share. As well, the Company issued $5 million in regular common shares to Mr. J.C. Anderson, Chairman of the Board. These shares were priced at $4.58 per share, being the five day weighted average price of the Company shares for the period ended September 5, 2006. Mr. Anderson purchased common shares in lieu of flow through common shares as he is both a Canadian and U.S. citizen and as such is unable to take full advantage of flow through share deductions. Total net proceeds were $19 million after commission and expenses. Proceeds will be used to drill 55 gross Edmonton Sands gas wells in the Sylvan Lake area.

Capital Budget and Production Guidance:

The Company has not altered its 2006 production guidance. The additional wells drilled using the proceeds of the equity issues will not be tied in for production until the first quarter of 2007 at the earliest.

Projected capital spending for 2006 is estimated to be approximately $75 to $80 million depending on weather and ground conditions. Capital spending includes $6.8 million in property acquisitions completed by the issuance of Company shares, $2.5 million for cash acquisitions and is net of $12.3 million for property dispositions.

Reserves:

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, 2006. The interim reserves evaluation incorporates reserves additions and revisions for the first ten months of the year. The first phase is not the Company's annual reserves report. The Company will be completing its annual reserves evaluation in early March, 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, 2006 price forecast. At that time, the Company will be making the customary annual reserves information filings as part of the year end reporting process.

Effective October 31, 2006, the Company's total proved reserves are 14.7 MMBOE and total proved and probable reserves are 23.2 MMBOE, 53% and 27% increases over December 31, 2005 reserves respectively. Natural gas represents 94% of the total proved and total proved plus probable reserves. Crude oil represents 3.3% and 3.5% of the total proved and total proved plus probable reserves.

Outlook:

As of September 30, 2006, the Company has assembled a drilling inventory of approximately 956 gross (392 net) locations on its lands. Approximately 75% of the net locations are Edmonton Sands prospective, 15% are Horseshoe Canyon CBM development locations and the balance is distributed among the rest of the Company's projects. This represents a five year drilling inventory based on current plans. Since December 31, 2005, the Company has added 46 gross (35 net) sections of Edmonton Sands prospective lands in the Sylvan Lake area, for a total of 206 gross (105 net) sections as of November 13, 2006.

The warm winter conditions in January have had a negative impact on natural gas prices throughout 2006. The levels of natural gas storage are at historic highs heading into winter. The duration and severity of the winter will dictate the strength of natural gas prices.

The Company has physically hedged 15,000 GJ/day of natural gas production for December 2006 at an average price of $7.57/GJ and financially hedged 18,000 GJ/day of natural gas production at an average price of $7.79/GJ for January to March 2007.

The Company will be active in the fourth quarter, drilling Edmonton Sands wells with up to 40 gross (25 net) wells expected to be drilled. The Company will also be participating in 28 gross (5 net) outside operated Horseshoe Canyon CBM drilling programs. The cost of doing business in the past year has been unacceptable for the current natural gas pricing environment. The Company has made significant progress in the fourth quarter in working with its contractors and suppliers in getting costs down. The constant natural gas price needed over the life of the reserves to generate a 15% after tax rate of return in the Company's Edmonton Sands projects is $4.75/Mcf and for the Horseshoe Canyon CBM projects is $3.90/Mcf.

The Company announces the resignation of one its original directors, Tim Swinton. We thank Tim for his contributions to the Company over the last 41/2 years and wish him the best in his future endeavors.

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

Brian H. Dau, President and Chief Executive Officer

November 13, 2006


Management's Discussion and Analysis For the Nine Months Ended September 30, 2006 and 2005:

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, 2006 and 2005 and is based on information available as of November 13, 2006.

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 cash flow from operations and barrel of oil equivalent. Cash flow from operations as used in this report represents cash from operating activities before changes in non-cash working capital and asset retirement expenditures. Anderson Energy believes that cash flow from operations represents 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 barrel of oil equivalent (BOE) basis whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil and natural gas measurement units into one basis for improved analysis of results and comparisons with other industry participants. These terms are not defined by Canadian GAAP and therefore are referred to as non-GAAP measures.

All references to dollar values are to Canadian dollars unless otherwise stated.

Review of Financial Results:

Sales volumes for the nine months ended September 30, 2006 were 4,082 BOED, which was 131% higher than the previous year, but lower than anticipated due to the fire and explosion at the Sylvan Lake gas plant on July 4, 2006, various plant outages and delays in receiving certain regulatory approvals. This combined with declines in natural gas prices resulted in lower cash flow from operations than expected.

On September 25, 2006, the Company completed two equity financings for net proceeds of $19 million. This, combined with $12.3 million in property dispositions to November 13, 2006 has allowed the Company to maintain its capital program for 2006 and 2007.

The interim reserve evaluation completed by AJM Petroleum Consultants resulted in significant increases in both proved and proved plus probable reserves. This has lowered depletion and depreciation expense significantly in the third quarter.

Revenue and Production:

Gas sales made up 70% of Anderson Energy's total oil and gas sales for the three months ended September 30, 2006 compared to 77% of total oil and gas sales for the second quarter of 2006 and 88% of total oil and gas sales for the three months ended September 30, 2005. The lower percentage is reflective of lower natural gas prices relative to oil prices and the impact of shut-in production in the quarter.

The Company achieved average gas sales of 19.6 MMcfd in the third quarter of 2006. This compares to 21.7 MMcfd in the second quarter of 2006 and 12.0 MMcfd in the third quarter of 2005. Sales volume decreases are primarily attributable the fire and explosion at the Focus Energy Trust Sylvan Lake Gas Plant gas plant on July 4, 2006. This impacted approximately 5.9 MMcfd of the Company's production that is custom processed at this gas plant. The production was not fully brought back on until late August 2006.

Oil production averaged 585 bpd in the third quarter of 2006 as compared to 379 bpd in the second quarter of 2006 and 181 bpd in the third quarter of 2005. Oil production was higher in the third quarter due to the Edberg oil property coming back onstream. Natural gas liquids production averaged 151 bpd in the third quarter of 2006 as compared to 170 bpd in the second quarter of 2006 and 69 bpd in the third quarter of 2005.

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 2006 2005 2006 2005
(thousands of dollars)

Natural Gas $ 10,316 $ 10,673 $ 36,090 $ 22,158
Oil 3,373 1,034 7,855 1,140
NGL 836 400 2,593 672
Royalty and other 126 40 454 89
--------------------------------------------------------------------------
Total $ 14,651 $ 12,147 $ 46,992 $ 24,059
--------------------------------------------------------------------------

Production
Natural gas (Mcfd) 19,621 11,991 20,691 9,940
Oil (bpd) 585 181 476 68
NGL (bpd) 151 69 158 42
--------------------------------------------------------------------------
Total (BOED) 4,006 2,249 4,082 1,767
--------------------------------------------------------------------------

Prices
Natural gas ($/Mcf) 5.71 9.68 6.39 8.17
Oil ($/bbl) 62.63 62.06 60.43 61.58
NGL ($/bbl) 60.24 62.94 60.23 58.28
Total ($/BOE) 39.41 58.49 41.76 49.68


Anderson Energy's average gas sales price was $5.71/Mcf for the three months ended September 30, 2006. This compares to $6.05/Mcf realized in the second quarter of 2006 and $9.68/Mcf realized in the third quarter of 2005.

Historically, Anderson Energy has sold most of its 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 16 MMcfd of natural gas sales for various terms ranging from one to three 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 has physical contracts to sell 15,000 GJ/day of natural gas for December 2006 at an average price of $7.57/GJ at AECO and 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 represents approximately 14 MMcfd of natural gas sales for December 2006 and 17 MMcfd of natural gas sales for January to March 2007.

Royalties:

Royalties were 21% of revenue in the third quarter of 2006, 22% of revenue in the second quarter of 2006 and 20% of revenue in the third quarter of 2005. The royalty rate in 2005 reflected a higher percentage of crown production and certain gas cost allowance adjustments. The Company expects 2006 royalties to increase overall as production increases. The average royalty rate on a percentage basis should be similar to current levels.

Operating Expenses:

Operating expenses were $10.94/BOE in the third quarter of 2006, $9.96/BOE for the second quarter of 2006 and $9.77/BOE for the third quarter of 2005. Workover costs and the impact of the Sylvan Lake plant explosion and fire affected operating costs in the third quarter of 2006 in aggregate and on a BOE basis. Operating costs are expected to increase overall as production increases. As the Company's four well per section Edmonton production increases in the latter part of 2007, Edmonton operating costs per BOE should decrease as the fixed costs associated with the field compression used for the previous one well drilled per section are distributed to the newly drilled three wells per section, as typically only one field compressor is used per section of development.



Operating Netback:

September 30 September 30
-------------------- ------------------
2006 2005 2006 2005
(thousands of dollars)
Revenue $ 14,651 $ 12,147 $ 46,992 $ 24,059
Royalties (3,064) (2,427) (10,334) (4,773)
Operating expenses (4,031) (2,021) (10,951) (4,590)
-------------------- -------------------
$ 7,556 $ 7,699 $ 25,707 $ 14,696
-------------------- -------------------

Sales (MBOE) 368.6 206.9 1,114.5 482.3

($/BOE)
Revenue $ 39.75 $ 58.69 $ 42.16 $ 49.88
Royalties (8.31) (11.73) (9.27) (9.90)
Operating expenses (10.94) (9.77) (9.83) (9.52)
-------------------- -------------------
$ 20.50 $ 37.19 $ 23.06 $ 30.46
-------------------- -------------------


General and Administrative Expenses:

General and administrative expenses were $3.72/BOE in the third quarter of 2006, $3.23/BOE in the second quarter of 2006 and $4.39/BOE in the third quarter of 2005. On a BOE basis, general and administrative costs increased in the third quarter due to lower production than in the second quarter. Total general and administrative expenses have increased as a result of increased staffing levels to manage the growth in drilling activity. General and administrative expenses consist largely of salaries, rent, computer and other office costs. As its production increases, general and administrative costs on a per BOE basis are expected to decline.



Three months ended Nine months ended
September 30 September 30
-------------------- ------------------
2006 2005 2006 2005
General and administrative
(gross) $ 2,463 $ 1,669 $ 7,484 $ 4,004
Overhead recoveries (411) (216) (1,523) (517)
Capitalized (683) (544) (2,210) (944)
---------------------------------------------------------------------------
General and administrative (net) $ 1,369 $ 909 $ 3,751 $ 2,543
---------------------------------------------------------------------------

General and administrative
($/BOE) $ 3.72 $ 4.39 $ 3.37 $ 5.27

% G&A capitalized 28% 33% 30% 24%


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

Interest Expense:

Interest expense was $0.5 million in the third quarter, $0.5 million in the second quarter of 2006 and $0.1 million in the third quarter of 2005. Interest expense is expected to increase in future quarters as a result of higher debt levels associated with the Company's capital program and higher interest rates.

Depletion, Depreciation and Amortization:

Depletion and depreciation was $21.62/BOE in the third quarter of 2006, $27.59/BOE for the second quarter of 2006 and $27.65/BOE in the third quarter of 2005. Depletion and depreciation expense is calculated based on proved reserves only and in previous quarters was significantly impacted by the fact that only 53% of the Company's total reserves were proved. The ratio reflected the newness of the wells that made up the reserve evaluation. The recent reserve evaluation completed by AJM Petroleum Consultants increased this ratio to 63% as well as increasing the overall amount of reserves which has resulted in a significant decrease in depletion and depreciation expense.

Asset Retirement Obligations:

As a result of new drilling, the Company incurred $0.6 million in asset retirement obligations in the third quarter of 2006, $0.7 million in the second quarter of 2006 and $0.6 million in the third quarter of 2005. Accretion expense was $0.2 million for the third quarter of 2006, $0.2 million for the second quarter of 2006 and $0.01 million in the third quarter of 2005 and was included in depletion and depreciation expense.

Income Taxes:

The Company is not currently taxable. The Company has approximately $185 million in available tax pools as of September 30, 2006.

Cash Flow from Operations:

Cash flow from operations for the three months ended September 30, 2006 was $5.9 million, $6.7 million in the second quarter of 2006 and $6.7 million during the third quarter of 2005. The decrease in cash flow from operations from the previous quarter was primarily due to the decreases in natural gas production as a result of the Sylvan Lake Gas Plant explosion and fire, lower oil and gas prices and higher operating costs.

Earnings:

The Company reported a $1.5 million loss in the third quarter of 2006 compared to a $1.7 million loss in the second quarter. Significantly lower depletion and depreciation expense in the third quarter due to higher proved reserves assigned in the interim reserve evaluation was offset by lower cash flow from operations. In addition, a one time future tax recovery of $1.2 million related to tax rate changes was recorded in the second quarter of 2006.



Capital Expenditures:
---------------------------------------------------------------------------

The Company spent $62.0 million in capital additions for the first nine
months of 2006. The breakdown of expenditures is shown below:

Nine months ended
(thousands of dollars) September 30, 2006
-------------------
Land, geological & geophysical costs $ 4,653
Property acquisitions, net of dispositions (486)
Drilling, completion and recompletion 34,599
Facilities and well equipment 18,904
Office equipment and furniture 70
Capitalized G&A 2,210
Asset retirement costs 2,015
-------------------
Total $ 61,965
-------------------


In addition, a gross-up of capital costs and an associated future income tax liability of $3.1 million were recorded to reflect the fact that the property acquisitions for shares had minimal tax bases.



Drilling statistics are shown below:

Three months ended Sept 30 Nine months ended Sept 30
---------------------------- ----------------------------
2006 2005 2006 2005
Gross Net Gross Net Gross Net Gross Net

Gas 35.0 15.6 30.0 14.7 79.0 35.9 64.0 35.7
Oil - - - - 6.0 4.0 1.0 0.5
Dry 3.0 2.1 2.0 1.3 7.0 5.3 4.0 2.8
-----------------------------------------------------------
Total 38.0 17.7 32.0 16.0 92.0 45.2 69.0 39.0
-----------------------------------------------------------

Success rate (%) 92% 88% 94% 92% 92% 88% 94% 93%


For the third quarter of 2006, 60% of the gross wells drilled were in Sylvan Lake.

Liquidity and Capital Resources:

The Company expects to spend $75 to $80 million net of dispositions in capital in 2006, dependent on weather and ground conditions. The Company's cash flow and bank lines are adequate to fund the fourth quarter expenditures. Additional funding was obtained in the third quarter with the issue of $15.0 million in flow through common shares and $5.0 million in common shares issued under a private placement. The Company has a commitment to spend 20% of the gross flow through proceeds ($3 million) on Canadian Exploration Expenses ("CEE") and 80% of the gross flow through proceeds ($12 million) on Canadian Development Expenses ("CDE") by December 31, 2007. The Company is further committed to incur at least 40% ($4.8 million) of the CDE expenditures by December 31, 2006. The fixed price natural gas contracts entered into after the end of the quarter will help to protect the winter capital program from the risk that a warm winter results in lower natural gas prices.

In May 2006, the Company renewed its revolving credit facility increasing the borrowing base to $55 million. The reserve-based credit facility has a revolving period ending July 15, 2007, 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. The facility bears interest at the bank's prime lending rate, bankers' acceptance or LIBOR rates plus applicable margins. Loans are secured by a floating charge debenture over all assets and guarantees by material subsidiaries.

As of November 13, 2006, there are 53.6 million common shares outstanding and 4.8 million stock options outstanding.

Related Party Transactions:

In the first and second quarters of 2006, the Company issued 558,102 common shares at an average price of $6.82 per share or $3.8 million as consideration for the purchase of three property acquisitions from companies controlled by a director of Anderson Energy. The share price was based on the five day average of the closing price of the Company's shares at the time of the agreements were entered into. The three transactions were completed under the same terms and conditions as other property acquisitions completed for shares in the same period and were approved by the independent directors of the Company and the TSX prior to completion. The assets acquired in these transactions and other property acquisitions for shares were silent partner working interests. These acquisitions increased and simplified the Company's working interests in a number of assets acquired as part of the Aquest Energy corporate acquisition in 2005.

In the third quarter of 2006, the Company issued 1,091,703 common shares to the Chairman of the Board of the Company at a price of $4.58 per share for total proceeds of $5.0 million pursuant to a private placement. Other directors and officers purchased 255,320 flow through common shares priced at $4.70 per share for total proceeds of $1.2 million as part of a $15.0 million public offering of flow through shares. The private placement shares were priced at the five day weighted average price of the Company shares for the period ended September 5, 2006. Mr. Anderson purchased regular common shares in lieu of flow through common shares as he is both a Canadian and U.S. citizen and as such is unable to take full advantage of flow through share deductions.

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 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.

The Company 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. The Company 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.

Business Prospects:

The Company has an excellent drilling inventory with over five years of development drilling locations. With the resumption of production through the Focus Energy Trust gas plant, the Company was able to resume spending activities in the vicinity of that plant. The recent weakness in natural gas prices has reduced competition for industry services. The Company is working with its suppliers and service companies to bring the cost of services down. Timing of AEUB regulatory applications continues to be slower than expected. With the Company's extensive drilling inventory and advance planning, the Company can manage the slower pace of regulatory approvals and the requirements for extensive landowner consultation.

The Company has affirmed its 2006 average production guidance of 4,000 to 4,300 BOED and its 2006 exit production guidance of 5,000 BOED. Risks associated with this estimate include gas plant capacity, regulatory issues and weather problems.

The Company will continue to develop its Edmonton Sands drilling opportunities, including exploring for new Edmonton Sands prospective areas, drilling 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)

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

Oil & gas revenue before royalties $ 14,651 $ 15,452 $ 16,889 $ 22,894
Cash flow from operations $ 5,873 $ 6,728 $ 8,604 $ 13,187
Cash flow 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 $ 11,592 $ 16,653 $ 33,720 $ 25,634
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


Q3 2005 Q2 2005 Q1 2005 Q4 2004
---------------------------------------

Oil & gas revenue before royalties $ 12,147 $ 6,646 $ 5,266 $ 4,170
Cash flow from operations $ 6,746 $ 2,941 $ 2,581 $ 2,132
Cash flow from operations per share
Basic $ 0.18 $ 0.09 $ 0.08 $ 0.07
Diluted $ 0.17 $ 0.09 $ 0.07 $ 0.07
Earnings (loss) $ 543 $ (801) $ (773) $ (766)
Earnings (loss) per share
Basic $ 0.01 $ (0.02) $ (0.02) $ (0.03)
Diluted $ 0.01 $ (0.02) $ (0.02) $ (0.03)
Capital expenditures $ 14,960 $ 11,589 $ 20,545 $ 16,063
Daily sales
Natural gas (Mcfd) 11,991 9,623 8,165 6,799
Liquids (bpd) 250 50 28 25
BOE (bpd) 2,249 1,653 1,389 1,159
Average prices
Natural gas ($/Mcf) $ 9.68 $ 7.28 $ 6.96 $ 6.47
Liquids ($/bbl) $ 61.97 $ 54.59 $ 52.34 $ 51.19
BOE ($/BOE) $ 58.49 $ 43.98 $ 41.96 $ 39.08


ADVISORY:

Certain information regarding Anderson Energy Ltd. in this new 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 drilling, completion and construction of facilities, expected production rates, dates of commencement of production and capital expenditures and timing thereof, 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'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'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 does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

Disclosure provided herein in respect of barrels of oil equivalent (BOE) may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.



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

---------------------------------------------------------------------------
---------------------------------------------------------------------------
September 30, December 31,
2006 2005
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Assets

Current assets:
Cash and short term investments $ 19 $ 510
Accounts receivable and accruals 21,368 31,303
Prepaid expenses and deposits 1,809 1,562
---------------------------------------------------------------------------
23,196 33,375

Property, plant and equipment (note 1) 258,413 221,717

Goodwill 14,320 14,320

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$ 295,929 $ 269,412
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Liabilities and Shareholders' Equity

Current liabilities:
Accounts payable and accruals $ 34,271 $ 46,420
Capital taxes payable - 184
---------------------------------------------------------------------------
34,271 46,604

Bank loan (note 3) 25,084 11,368

Asset retirement obligations (note 2) 13,637 11,299

Future income taxes (note 5) 18,312 16,073
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91,304 85,344
Shareholders' equity:
Share capital (note 4) 208,780 184,315
Contributed surplus (note 4) 575 103
Deficit (4,730) (350)
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204,625 184,068

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$ 295,929 $ 269,412
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Subsequent events (note 8)

See accompanying notes to the consolidated financial statements.


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

---------------------------------------------------------------------------
---------------------------------------------------------------------------
Three months ended Nine months ended
September 30, September 30,
2006 2005 2006 2005
---------------------------------------------------------------------------

Revenues
Oil and gas sales $ 14,651 $ 12,147 $ 46,992 $ 24,059
Royalties (net of ARTC of $375,
$375 in 2005) (3,064) (2,427) (10,334) (4,773)
Interest income 38 48 73 275
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11,625 9,768 36,731 19,561
Expenses
Operating 4,031 2,021 10,951 4,590
General and administrative 1,369 909 3,751 2,543
Interest and other financing
charges 522 56 1,297 77
Depletion, depreciation and
accretion 8,212 5,803 29,012 13,659
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14,134 8,789 45,011 20,869

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Earnings (loss) before income
taxes (2,509) 979 (8,280) (1,308)

Taxes
Capital taxes - 64 - 116
Future income taxes (reduction)
(note 5) (1,000) 372 (3,900) (393)
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(1,000) 436 (3,900) (277)

---------------------------------------------------------------------------
Earnings (loss) for the period (1,509) 543 (4,380) (1,031)

Deficit, beginning of period (3,221) (2,655) (350) (1,081)

---------------------------------------------------------------------------
Deficit, end of period $ (4,730) $ (2,112) $ (4,730) $ (2,112)
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Earnings (loss) per share
Basic $ (0.03) $ 0.01 $ (0.09) $ (0.03)
Diluted $ (0.03) $ 0.01 $ (0.09) $ (0.03)

See accompanying notes to the consolidated financial statements.


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

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---------------------------------------------------------------------------
Three months ended Nine months ended
September 30, September 30,
2006 2005 2006 2005
---------------------------------------------------------------------------

Cash provided by (used in):

Operations
Earnings (loss) for the period $ (1,509) $ 543 $ (4,380) $ (1,031)
Items not involving cash
Depletion, depreciation and
accretion 8,212 5,803 29,012 13,659
Future income taxes
(reduction) (1,000) 372 (3,900) (393)
Stock based compensation 170 28 473 33
Asset retirement expenditures (90) (80) (363) (267)
Changes in non-cash working
capital
Accounts receivable and
accruals (874) (1,297) 4,926 (1,682)
Prepaid expenses and deposits 69 (114) (638) (158)
Accounts payable and accruals 894 2,052 (1,066) 3,709
Capital taxes payable - 34 (184) 20
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5,872 7,341 23,880 13,890
Financing
Increase (decrease) in bank
loan (12,115) 5,888 13,716 5,888
Issue of common shares 19,050 29,283 20,779 29,523
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6,935 35,171 34,495 35,411
Investments
Additions to property, plant
and equipment (16,236) (14,329) (62,929) (45,857)
Proceeds on sale of properties 5,287 - 9,746 1,000
Acquisition of Aquest - (1,042) - (1,042)
Payment of Aquest liabilities
assumed - (25,882) - (25,882)
Changes in non-cash working
capital
Accounts receivable and
accruals 228 (16,507) 5,009 (20,054)
Prepaid expenses and deposits 149 (705) 391 (646)
Accounts payable and accruals (2,302) 11,997 (11,083) 14,176
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(12,874) (46,468) (58,866) (78,305)

---------------------------------------------------------------------------
Decrease in cash (67) (3,956) (491) (29,004)

Cash and short-term
investments, beginning of
period 86 4,194 510 29,242
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Cash and short-term
investments, end of period $ 19 $ 238 $ 19 $ 238
---------------------------------------------------------------------------
---------------------------------------------------------------------------

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, 2006 and 2005
(tabular amounts in thousands of dollars, unless otherwise stated)


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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, 2005. 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, 2005.



1. Property, plant and equipment:

---------------------------------------------------------------------------
---------------------------------------------------------------------------
September 30, December 31,
2006 2005
---------------------------------------------------------------------------
Cost $320,311 $255,289
Less accumulated depletion and depreciation (61,898) (33,572)
---------------------------------------------------------------------------
Net book value $258,413 $221,717
---------------------------------------------------------------------------
---------------------------------------------------------------------------


At September 30, 2006, unproved property costs of $23.3 million (December 31, 2005 - $22.6 million) have been excluded from the full cost pool for depletion and depreciation calculations. Future development costs of proved, undeveloped reserves of $90.1 million (December 31, 2005 - $73.5 million) have been included for depletion, depreciation and impairment test calculations.

For the nine months ended September 30, 2006, $2.2 million (September 30, 2005 - $0.9 million) of general and administrative costs were capitalized. Capitalized general and administrative costs consist of salaries and associated office rent of staff involved in capital activities.

No impairment was recognized under the ceiling test at September 30, 2006. The future commodity prices used in the ceiling test were based on commodity price forecasts adjusted for differentials specific to the reserves.

2. Asset retirement obligations:

The Company estimates the total undiscounted cash flows required to settle its asset retirement obligations is approximately $25.6 million, including expected inflation of 2% per annum. The majority of the costs will be incurred between 2006 and 2016. 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:

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---------------------------------------------------------------------------
September 30, December 31,
2006 2005
---------------------------------------------------------------------------
Balance, beginning of period $11,299 $ 2,094
Liabilities incurred during period 2,015 3,338
Liabilities assumed on Aquest Energy acquisition - 5,822
Liabilities settled in period (363) (310)
Accretion expense 686 355
---------------------------------------------------------------------------
$13,637 $11,299
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3. Bank loan:

In May 2006, the Company renewed its revolving credit facility with a Canadian bank, increasing the borrowing base to $55 million. The reserve-based credit facility has a revolving period ending July 15, 2007, 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. Share capital and contributed surplus:

Issued share capital

---------------------------------------------------------------------------
---------------------------------------------------------------------------
Number of Amount
Common shares (thousands)
---------------------------------------------------------------------------
Balance at December 31, 2005 47,967,708 $184,315
Issued on property acquisitions 943,791 6,768
Issue of private placement common shares 1,091,703 5,000
Issue of flow-through common shares 3,191,490 15,000
Share issue costs - (950)
Tax effect of share issue costs - 299
Stock options exercised 393,224 1,729
Transferred from contributed surplus on
stock option exercise - 1
Tax effect of flow-through share renouncements - (3,382)

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Balance at September 30, 2006 53,587,916 $208,780
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---------------------------------------------------------------------------


Flow-through shares

Under flow-through share agreements entered into in 2005, the Company committed to incur $10,000,000 of qualifying Canadian Exploration Expenses by December 31, 2006. The renouncements were made February 28, 2006 with an effective date of December 31, 2005. At September 30, 2006, all of the qualifying expenditures had been made.

Under flow-through share agreements entered into in 2006, the Company committed to incur $15,000,000 of qualifying expenditures by December 31, 2007. The Company will use 20% of the gross proceeds to incur Canadian Exploration Expenses and 80% to incur Canadian Development Expenses which will be renounced in February 2007 and February 2008 related to the 2006 and 2007 taxation years respectively.

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, 2006 are as follows:



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

Balance at December 31, 2005 4,179,355
Granted 1,476,600
Exercised (393,224)
Expirations and cancellations (410,640)

---------------------------------------------------------------------------
Balance at September 30, 2006 4,852,091

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


The outstanding options at September 30, 2006 had an average exercise price of $4.91 per share and a weighted average remaining contractual life of 5.3 years; 2,764,658 of the options were exercisable at that date.

The fair value of the options issued in 2006 ranged between $1.51 to $2.07 per option. The weighted average assumptions used in arriving at these values were: a risk-free interest rate of between 3.9% to 4.5%, expected option life of 4 years, expected volatility of between 25% to 35% and a dividend yield of 0%.

Per share amounts

During the period ended September 30, 2006 there were 48,993,371 weighted average shares outstanding (September 30, 2005 - 35,160,340). On a diluted basis, there were 49,977,007 weighted average shares outstanding (September 30, 2005 - 36,072,865) after giving effect to dilutive stock options.



Contributed surplus

---------------------------------------------------------------------------
---------------------------------------------------------------------------
Amount
---------------------------------------------------------------------------
Balance at December 31, 2005 $103
Stock based compensation 473
Transferred from contributed surplus on stock option exercise (1)
---------------------------------------------------------------------------

Balance at September 30, 2006 $575
---------------------------------------------------------------------------
---------------------------------------------------------------------------


5. Taxes

In May 2006, the Company recorded a $1.2 million future tax benefit related to enacted federal and provincial income tax rate reductions.



6. Cash payments

The following cash payments were made (received):

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---------------------------------------------------------------------------
September 30, September 30,
2006 2005
---------------------------------------------------------------------------

Interest paid $1,218 $ 54
Interest received (73) (303)
Taxes paid 304 80

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


7. Related party transactions:

At September 30, 2006, accounts receivable include $41,000 due from companies controlled by a director of the Company and accounts payable include $57,800 due to a company controlled by a director of the Company. The director was previously a director of Aquest Energy Ltd. (a company purchased by Anderson Energy in 2005) and the amounts arise as a result of common joint venture interests held by the director and Aquest Energy. The transactions have been recorded under the same terms and conditions as transactions with unrelated parties.

From February to May 2006, the Company issued 943,791 common shares at an average price of $7.17 per share as consideration for the purchase of seven property acquisitions. Five of the transactions were producing property acquisitions where the Company acquired partner minority interests in former Aquest Energy properties. Three of the transactions were with companies controlled by a director of Anderson Energy, for a total consideration of 558,102 shares at an average purchase price of $6.82 per share or $3.8 million. The three transactions were completed under the same terms and conditions as the other transactions and were approved by the TSX prior to completion.

In September 2006, the Company issued 1,091,703 common shares to the Chairman of the Board of the Company at a price of $4.58 per share for total proceeds of $5.0 million pursuant to a private placement. Other directors and officers purchased 255,320 flow through common shares priced at $4.70 per share for total proceeds of $1.2 million as part of a $15.0 million public offering of flow through shares.

8. Subsequent events:

In October 2006, the Company completed the sale of certain producing properties for total proceeds of $2.6 million.



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

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Natural Gas Volume/day Average Price
---------------------------------------------------------------------------
Physical Sales Contracts

December 2006 15,000 GJ/day $7.57/GJ

Financial Swap Contracts

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

Head Office
700 Canterra Tower
400 3rd Avenue S.W.
Calgary, Alberta
Canada T2P 4H2
Phone (403) 262-6207
Fax (403) 261-2792

Directors Officers

J.C. Anderson(1) 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)
Calgary, Alberta M. Darlene Wong
Vice President Finance, Chief
Glenn D. Hockley(3) Financial Officer & Secretary
Calgary, Alberta
Blaine M. Chicoine
David G. Scobie(1)(2)(3) Vice President, Operations
Calgary, Alberta
Philip A. Harvey
Vice President, Exploration

Daniel F. Kell
Vice President, Land

David M. Spyker
Vice President, Business
Development

Member of
(1) Audit Committee
(2) Compensation and Corporate
Governance Committee
(3) Reserves Committee


Auditors
KPMG LLP
Calgary, Alberta

Independant Engineers
AJM Petroleum Consultants

Legal Counsel
Bennett Jones LLP

Registrar & Transfer Agent
Valiant Trust Company

Stock Exchange
The Toronto Stock Exchange
Symbol AXL

Abbreviations used:

bbls - barrels
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 of barrels of oil equivalent
Mcf - thousand cubic feet
Mcfd - thousand cubic feet per day
Mcfe - thousand cubic feet equivalent
MMcf - million cubic feet
MMcfd - million cubic feet per day
GJ - gigajoule



Contact Information

  • Anderson Energy Ltd.
    Brian H. Dau
    President and Chief Executive Officer
    (403) 206-6000