Anderson Energy Ltd.
TSX : AXL

Anderson Energy Ltd.

March 19, 2007 08:00 ET

Anderson Energy Ltd. Announces 2006 Fourth Quarter and Year End Results

CALGARY, ALBERTA--(CCNMatthews - March 19, 2007) - Anderson Energy Ltd. ("Anderson Energy" or "the Company") (TSX:AXL) is pleased to announce its operating and financial results for the fourth quarter and year ended December 31, 2006.

Highlights:

- The Company's finding, development and acquisition costs including future development capital ("F,D&A") for the year ended December 31, 2006 were $13.34/BOE total proved and $13.40/BOE total proved plus probable.

- The Company's December 31, 2006 reserves are 16.2 MMBOE total proved and 25.1 MMBOE total proved plus probable, 69% and 37% increases respectively over 2005 total proved and total proved plus probable reserves.

- The Company replaced production by a factor of 544% with total proved reserves and 550% with total proved plus probable reserves. The Company's reserves life indices are 9.5 years total proved and 14.6 years total proved plus probable using 2006 year end production.

- Current production is approximately 4,600 BOED. Chinchaga production is expected to resume this week, which will add 400 BOED of production. Behind pipe production capability is approximately 1,200 BOED. Fourth quarter production averaged 4,205 BOED, an increase of 5% over the third quarter of 2006 and 13% over the fourth quarter of 2005.

- As of December 31, 2006, the Company's drilling inventory is 913 gross (379 net) locations. The Edmonton Sands project represents 76% of the net inventory. The Horseshoe Canyon Coal Bed Methane project represents 15% of the net inventory.

- Cash flow from operations in the fourth quarter of 2006 was $8.0 million or $0.15/share, an increase of $2.1 million over the third quarter of 2006 and a decrease of $5.2 million from the fourth quarter of 2005.

- The average natural gas price was $6.82/Mcf in the fourth quarter of 2006, an increase of $1.11/Mcf from the third quarter of 2006 and a decrease of $4.57/Mcf from the $11.39/Mcf received in the fourth quarter of 2005.

- Drilling for the three months ended December 31, 2006 resulted in 54 gross (38.6 net) wells drilled with a success rate of 89%. Drilling results for the year ended December 31, 2006 resulted in 146 gross (83.8 net) wells drilled with a success rate of 88%.



Financial and Operating Highlights

Three
months ended % Year ended %
December 31 Change December 31 Change
-------------- --------------
2006 2005 2006 2005
Financial
(thousands of dollars,
except share data)

Total oil and gas
revenue $ 16,820 $ 22,894 (27%) $ 63,812 $ 46,953 36%

Cash flow from
operations $ 7,996 $ 13,187 (39%) $ 29,201 $ 25,454 15%
Per common share
- basic $ 0.15 $ 0.28 (46%) $ 0.58 $ 0.66 (12%)
- diluted $ 0.15 $ 0.27 (44%) $ 0.58 $ 0.65 (11%)

Earnings (loss) 846 1,762 (52%) (3,534) 731 (583%)
Per common share
- basic $ 0.02 $ 0.04 (50%) $ (0.07) $ 0.02 (450%)
- diluted $ 0.02 $ 0.04 (50%) $ (0.07) $ 0.02 (450%)

Capital
expenditures 22,068 25,635 (14%) 84,033 72,730 16%
Corporate acquisition - 80,589 (100%)
Debt, net of working
capital 48,653 24,597 98%

Shareholders' equity 205,930 184,068 12%
Average shares
outstanding
(thousands)
Basic 53,641 47,902 12% 50,165 38,372 31%
Diluted 53,681 48,791 10% 50,248 39,309 28%

Ending shares
outstanding (thousands) 53,641 47,968 12%

Operating (6 Mcf:1bbl
conversion)

Average daily sales
Natural gas (Mcfd) 21,075 18,785 12% 20,787 12,170 71%
Light/medium crude
oil (bpd) 512 409 25% 485 154 215%
NGL (bpd) 180 168 7% 163 74 120%
Barrels of oil
equivalent (BOED) 4,205 3,708 13% 4,113 2,256 82%

Average sales price
Natural gas ($/Mcf) 6.82 11.39 (40%) 6.50 9.42 (31%)
Light/medium crude
oil ($/bbl) 50.61 51.34 (1%) 57.81 54.72 6%
NGL ($/bbl) 52.49 58.97 (11%) 58.07 58.41 (1%)
Barrels of oil
equivalent ($/BOE) 42.62 66.05 (35%) 41.98 56.46 (26%)

Royalties ($/BOE) 7.68 15.83 (51%) 8.86 12.35 (28%)
Operating costs ($/BOE) 10.30 8.47 22% 9.95 9.08 10%
Operating netbacks
($/BOE) 25.50 42.81 (40%) 23.69 35.57 (33%)
General and
administrative ($/BOE) 3.81 3.51 9% 3.48 4.54 (23%)

Wells drilled (gross) 54 49 10% 146 118 24%


Production:

Fourth quarter production was negatively impacted by the curtailment of Chinchaga production through the outside operated Ladyfern gas plant. Hydrocarbon dew point control at the subject gas plant was altered for safety concerns, which shut-in third party gas being processed at the Ladyfern gas plant. The Company produced Chinchaga sporadically in early October, with the field fully shut-in in early November. This impacted 1.8 Mmcfd of gas sales at Chinchaga. The Chinchaga field is estimated to resume production this week, with the gas now being custom processed at the Hamburg gas plant. On January 11, 2007, the Company reported production of 4,900 BOED including some flush production related to wells tied-in late in the year. The Company was able to offset some of the impact of the shut-in at Chinchaga and the deferral of outside operated CBM drilling and tie-in projects with Edmonton Sands well tie-ins during the fourth quarter.

Current production is approximately 4,600 BOED. Chinchaga production is expected to resume this week, which will add 400 BOED of production. Current production is influenced by flush production associated with recent Edmonton Sands well tie-ins. The Company has approximately 1,200 BOED of production capability behind pipe, of which 80% is estimated to be on-stream by the end of the third quarter of 2007. The Company has four significant large compression/pipeline projects in the Sylvan Lake area representing 25% of behind pipe production. These projects have been delayed from anticipated first quarter start up to the second and third quarters of 2007.

Operations:

During the fourth quarter of 2006, the Company drilled 54 gross (38.6 net) wells with a success rate of 89%. Edmonton Sands drilling in the quarter was 43 gross (36.6 net) wells. The average working interest for Edmonton Sands wells increased to 83% due to the significant number of new farm-in opportunities drilled in the fourth quarter. Outside operated Horseshoe Canyon Coal Bed Methane ("CBM") drilling was less than anticipated, with 9 gross (1.4 net) wells drilled in the fourth quarter of 2006 and 9 gross (1.8 net) wells drilled in the first quarter of 2007. The remaining 2006 CBM locations that were deferred to 2007 are now expected to be drilled in the third quarter.

Capital spending in the quarter was $22.1 million (net of dispositions), of which $16.2 million was spent on drilling and completion expenditures and $5.7 million was directed at facility expenditures. Dispositions were $2.7 million in the quarter. As part of the flow-through share financing completed in September 2006, the Company committed to spend 40% of the CDE dollars in 2006 and 60% in 2007. As a result of an acceleration of its drilling program in the fourth quarter, the Company completed the entire CDE commitment in 2006, to the benefit of the flow-through subscribers.

In 2006, the Company drilled 146 gross (83.8 net) wells with a success rate of 88%. In the Edmonton Sands project, the Company drilled 87 gross (60.8 net) gas wells. In 2006, the Company participated in 30 gross (5 net) Horseshoe Canyon CBM gas wells.

Acquisitions and Dispositions:

In 2006, the Company completed nine acquisition and eight disposition transactions for a total of $9.6 million in net cash disposition proceeds. The Company also issued 0.9 million shares for acquisitions.

Winter Drilling Update:

The Company has drilled 41 gross (24.8 net) wells to date in the first quarter of 2007 with a success rate of 88%. Edmonton Sands drilling represents 82% of the total net wells drilled.

At Chinchaga, the Company participated in a 39% working interest development well. The well is tied-in and should be on production this week. Expected stabilized rates are one million cubic feet per day on this well. Also at Chinchaga, new compression and dehydration facilities and a pipeline connection to the Hamburg gas plant were completed, allowing Chinchaga production to flow to the Hamburg plant this week.

2006 Reserves Evaluation:

AJM Petroleum Consultants ("AJM") completed their annual NI 51-101 compliant reserves evaluation of all of the Company's reserves. The details of the evaluation will be summarized in the Company's Annual Information Form ("AIF") to be filed later this month on SEDAR. A brief summary is shown below:



Total Proved
Total Proved plus Probable
(MBOE) (MBOE)
----------------------------
Opening balance, December 31, 2005 9,584 18,336

Acquisitions 4,422 4,432
Additions 2,869 4,616
Revisions 868 (785)
Production (1,501) (1,501)
----------------------------

Net change 6,658 6,762

----------------------------
Ending balance, December 31, 2006 16,242 25,098
----------------------------
----------------------------


The Company replaced 544% of its production with total proved reserves and 550% of its production with total proved plus probable reserves and grew its overall proved and proved plus probable reserve base by 69% and 37% respectively during the year. The Company had significant negative revisions in Sierra on a total proved and total proved plus probable basis. Significant total proved positive additions from the Edmonton Sands project more than offset the negative Sierra revisions. Acquisitions include reserves acquired through property acquisitions and through farm-ins.

Finding, Development and Acquisition Results:

Finding, development and acquisition results, including the change in future development capital, for the year ended December 31, 2006 are $13.34/BOE total proved and $13.40/BOE total proved plus probable, which are 51% lower on a total proved and 29% lower on a total proved plus probable basis than 2005. The changes in future development capital in the above calculations are $3.43/BOE total proved and $3.61/BOE total proved plus probable. More detail on F,D&A and F,D&A cautionary language is contained in the attached Management's Discussion and Analysis.

Net Asset Value:

The Company's estimated net asset value per share calculation as of December 31, 2006 is outlined below:



(thousands of dollars, except share data)
Pretax proved plus probable reserves
NPV10%, escalating prices (note 1) $ 263,976
Undeveloped land (188,184 net acres at $143 per acre)
(note 2) 27,066
Debt, net of working capital (48,653)
----------------------------------------------------------------------------
Total $ 242,389
Number of common shares (thousands) 53,641
Net asset value per share $ 4.52
----------------------------------------------------------------------------
(1) based on an independent evaluation conducted by AJM Petroleum
Consultants effective December 31, 2006
(2) based on an independent evaluation conducted by Seaton-Jordan &
Associates Ltd. effective December 31, 2006


The first year gas price used in AJM's price forecast is $7.40/Mcf at AECO.

Outlook:

As of December 31, 2006, the Company has assembled a drilling inventory of 913 gross (379 net) locations on its lands. Approximately 76% of the net locations are Edmonton Sands prospective, 15% are Horseshoe Canyon CBM development locations and the balance is distributed amongst the Company's other projects. This represents a five year drilling inventory. After adjusting for wells drilled during the year, the Company added 207 gross (173 net) locations to the drilling inventory since December 31, 2005. As of March 15, 2007, the Company controls or has an interest in 225 gross (119 net) sections of land in the Edmonton Sands project.

The Company has established a preliminary capital spending program of $50 million for 2007. The Company expects to drill 108 gross (54 net) wells with almost 74% of the net drilling count being Edmonton Sands wells. Depending on the strength of natural gas prices and the cost of doing business, the Company will revisit its spending plans throughout the year. The Company can easily scale up its capital program by drilling more Edmonton Sands locations.

The warm winter in 2005/2006 had a negative impact on natural gas prices and North American natural gas storage. The El Nino weather impact on the start of the winter of 2006/2007 has also resulted in weak natural gas prices and North American natural gas storage being higher than historical standards. The cold weather seen in February 2007 has significantly reduced the US storage from the previous year. An expected reduction in Canadian drilling activity should, over time, impact the supply of natural gas and correct the storage imbalance. A warm North American summer and the onset of winter would also have a positive influence on natural gas prices in 2007.

In the balance of the year, the Company continues to add to its opportunity base with additional farm-in deals on Edmonton Sands wells. As well, with the recently proposed changes in Income Trust taxation, the Company believes the acquisition market may prove to be economic for junior companies.

The Company will be publishing its annual report at the end of March 2007. In this report, we will provide a more detailed operational overview on the Company's activities. We invite our shareholders to attend the Company's second annual meeting as a public company on May 9, 2007 at the Metropolitan Centre in Calgary at 2:00 p.m.

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

March 19, 2007

Management's Discussion and Analysis

For the Years Ended December 31, 2006 and 2005:

The following discussion and analysis of financial results should be read in conjunction with the audited consolidated financial statements of Anderson Energy Ltd. ("Anderson Energy" or "the Company") for the year ended December 31, 2006 and 2005 and is based on information available as of March 14, 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 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.

The abbreviations used in this discussion and analysis are located on the last page of this press release.

Review of Financial Results

Sales volumes for the year ended December 31, 2006 were 4,113 BOED, which was 82% 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.

Net capital expenditures in the year were $84.0 million. Reserves were added at a finding, development and acquisition cost (including future development capital) of $13.34 per BOE for proved reserves and $13.40 per BOE for proved and probable reserves.

Net capital expenditures include nine property acquisitions, purchased for $2.8 million in cash and the issuance of 943,791 common shares worth $6.8 million, and eight property dispositions for proceeds of $12.4 million cash. The transactions simplified the Company's working interest in a number of assets acquired as part of the Aquest Energy Ltd. corporate acquisition in 2005.

On September 25, 2006, the Company completed two equity financings for net proceeds of $19 million. This, combined with the property dispositions noted above and an increase in its bank line to $75 million, allowed the Company to maintain its capital programs for 2006 and 2007 in spite of lower prices and events beyond the Company's control that delayed bringing on certain production.

The 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 last half of the year.

Revenue and Production:

Gas sales made up 84% of Anderson Energy's total oil and gas sales volumes for the year ended December 31, 2006 compared to 90% of total oil and gas sales volumes for the year ended December 31, 2005.

Gas sales volumes for the year ended December 31, 2006 increased 71% to 20.8 MMcfd from 12.2 MMcfd last year. The increase reflects the acquisition of Aquest Energy in September 2005 and new wells on production as a result of drilling during the year. As a result of both of these factors, Greater Sylvan Lake has become the Company's largest area of production, with gas sales of 11.2 MMcfd, followed by north central Alberta with gas sales of 5.6 MMcfd and northeast British Columbia with gas sales of 1.8 MMcfd. Gas sales volumes were negatively impacted in the year by a fire and explosion at the Focus Energy Trust Sylvan Lake gas plant on July 4, 2006. This impacted approximately 5.9 MMcfd of the Company's production that was custom processed at the plant. The production was not fully brought back on until late August 2006. Sales volumes were also impacted by the shut-in of production at Chinchaga and the deferral of certain non-operated Coal Bed Methane drilling at Ghost Pine in the fourth quarter. Approximately 1.8 MMcfd was shut in at Chinchaga due to dewpoint control problems in the third party operated Ladyfern gas plant. Production will resume at Chinchaga when the property is connected to the third party operated Hamburg gas plant in March 2007. Other plant outages and delays in receiving regulatory approvals for holding applications also had an impact on the timing of production coming on stream.

The Company achieved average gas sales of 21.1 MMcfd in the fourth quarter of 2006. This compares to 19.6 MMcfd in the third quarter of 2006 and 18.8 MMcfd in the fourth quarter of 2005. Fourth quarter gas sales reflected the return of production at Sylvan Lake and the shut-in of production at Chinchaga.

Oil sales for year ended December 31, 2006 were 485 bpd compared to 154 bpd for the year ended December 31, 2005. Oil production averaged 512 bpd in the fourth quarter of 2006 compared to 585 bpd in the third quarter of 2006 and 409 bpd in the fourth quarter of 2005. The majority of the oil production is from central and eastern Alberta.

Natural gas liquids sales for the year ended December 31, 2006 were 163 bpd compared to 74 bpd for the year ended December 31, 2005. Natural gas liquids sales averaged 180 bpd in the fourth quarter of 2006 compared to 151 bpd in the third quarter of 2006 and 168 bpd in the fourth quarter of 2005. Edmonton Sands natural gas production at Sylvan Lake is dry and produces minimal amounts of natural gas liquids.

The following tables outline production revenue, volumes and average sales prices for the year and for the fourth quarter.



Three months ended Dec 31 Year ended Dec 31
------------------------- ---------------------
2006 2005 2006 2005
------------------------- ---------------------

Oil and Natural Gas Revenue
(thousands of dollars)
Natural gas $ 13,232 $ 19,690 $ 49,322 $ 41,847
Oil 2,385 1,934 10,240 3,075
NGL 870 911 3,463 1,583
Royalty and other 333 359 787 448
------------------------- ---------------------
Total $ 16,820 $ 22,894 $ 63,812 $ 46,953
------------------------- ---------------------
------------------------- ---------------------

Three months ended Dec 31 Year ended Dec 31
------------------------- ---------------------
2006 2005 2006 2005
------------------------- ---------------------
Production
Natural gas (Mcfd) 21,075 18,785 20,787 12,170
Oil (bpd) 512 409 485 154
NGL (bpd) 180 168 163 74
------------------------- ---------------------
Total (BOED) 4,205 3,708 4,113 2,256
------------------------- ---------------------
------------------------- ---------------------

Three months ended Dec 31 Year ended Dec 31
------------------------- ---------------------
2006 2005 2006 2005
------------------------- ---------------------
Prices
Natural gas ($/Mcf) $ 6.82 $ 11.39 $ 6.50 $ 9.42
Oil ($/bbls) 50.61 51.34 57.81 54.72
NGL ($/bbls) 52.49 58.97 58.07 58.41
------------------------- ---------------------
Total ($/BOE) $ 42.62 $ 66.05 $ 41.98 $ 56.46
------------------------- ---------------------
------------------------- ---------------------


Anderson Energy's average gas sales price was $6.50 per Mcf for the year ended December 31, 2006 compared to $9.42 per Mcf for the year ended December 31, 2005. For the three months ended December 31, 2006, the gas sales price was $6.82 per Mcf. This compares to $5.71 per Mcf realized in the third quarter of 2006 and $11.39 per Mcf realized in the fourth quarter of 2005. Gas prices decreased significantly over the course of the year due to warm winter conditions early in the year and historically high levels of natural gas storage. Gas prices have improved somewhat in 2007 but will be dependent on the level of drilling that results in new supply and the weather conditions that affect demand for the product in North America.

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 16.6 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 had physical contracts to sell 15,000 GJ per day of natural gas for December 2006 at an average price of $7.57 per GJ at AECO and has financial swap contracts to sell 18,000 GJ per day of natural gas at an average price of $7.79 per 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 for the year ended December 31, 2006 compared to 22% of revenue for the year ended December 31, 2005. Royalties were 18% of the revenue in the fourth quarter of 2006 compared to 21% of revenue in the third quarter and 24% of revenue in the fourth quarter of 2005. Royalty rates were affected by lower gas prices and certain royalty credits received in British Columbia. On an absolute dollar basis, total royalties are expected to increase in 2007 as revenue increases. Royalty rates may increase in 2007 as a result of the elimination of the Alberta Royalty Tax Credit program on January 1, 2007 and more production from drilling on farm-in lands that may result in higher overriding royalty obligations.



Three months ended Dec 31 Year ended Dec 31
------------------------- ---------------------
2006 2005 2006 2005
------------------------- ---------------------
Royalties (%) 18% 24% 21% 22%
Royalties ($/BOE) $ 7.68 $ 15.83 $ 8.86 $ 12.35


Operating Expenses:

Operating expenses were $9.95 per BOE for the year ended December 31, 2006 compared to $9.08 per BOE for the year ended December 31, 2005. Operating expenses were $10.30 in the fourth quarter of 2006 compared to $10.94 in the third quarter and $8.47 in the fourth quarter of 2005. Workover costs and the impact of the Sylvan Lake gas plant explosion and fire affected operating costs in the third quarter of 2006 in aggregate and on a BOE basis. The shut-in at Chinchaga affected operating costs on a per BOE basis in the fourth quarter, as it is one of the lower operating cost properties on a per BOE basis. Operating costs are expected to increase overall as production increases, but as the Company's four wells per section Edmonton Sands production increases in the latter part of 2007, Edmonton Sands operating costs per BOE should decrease. Fixed costs associated with the field compression used for the previous one well drilled per section will be distributed to the newly drilled three wells per section, as typically only one field compressor is used per section of development.



Operating Netback:

Three months ended Dec 31 Year ended Dec 31
------------------------- ---------------------
(thousands of dollars) 2006 2005 2006 2005
------------------------- ---------------------

Revenue $ 16,820 $ 22,894 $ 63,812 $ 46,953
Royalties (2,971) (5,399) (13,305) (10,173)
Operating expenses (3,983) (2,890) (14,934) (7,480)
------------------------- ---------------------
$ 9,866 $ 14,605 $ 35,573 $ 29,300
------------------------- ---------------------
------------------------- ---------------------

Sales (MBOE) 386.9 341.2 1,501.3 823.6

Per BOE
Revenue $ 43.48 $ 67.11 $ 42.50 $ 57.01
Royalties (7.68) (15.83) (8.86) (12.35)
Operating expenses (10.30) (8.47) (9.95) (9.08)
------------------------- ---------------------
$ 25.50 $ 42.81 $ 23.69 $ 35.58
------------------------- ---------------------
------------------------- ---------------------


General and Administrative Expenses:

General and administrative expenses were $3.48 per BOE for the year ended December 31, 2006 compared to $4.54 per BOE for the year ended December 31, 2005. General and administrative expenses were $3.81 per BOE in the fourth quarter of 2006 compared to $3.72 per BOE in the third quarter and $3.51 per BOE in the fourth quarter of 2005. On an absolute basis, general and administrative expenses were higher in 2006 as a result of increased staffing levels to manage the growth in drilling activity. On a BOE basis, general and administrative expenses were affected by shut-in production at Sylvan Lake in the third quarter and at Chinchaga in the fourth quarter. As the Company increases its production in 2007, general and administrative costs on a per BOE basis are expected to decline.

The Company follows the CICA accounting standard requiring the fair value method of accounting for stock-based compensation plans. Stock-based compensation expense was $718,000 in 2006 ($362,000 net of amounts capitalized) versus $103,000 in 2005. The increase is a result of additional stock options being granted to new and existing staff members.



Three months ended Dec 31 Year ended Dec 31
------------------------- ---------------------
(thousands of dollars) 2006 2005 2006 2005
------------------------- ---------------------

General and administrative
(gross) $ 2,992 $ 2,430 $ 10,476 $ 6,426
Overhead recovery (498) (461) (2,021) (969)
Capitalized (1,019) (771) (3,229) (1,715)
------------------------- ---------------------
General and administrative
(net) $ 1,475 $ 1,198 $ 5,226 $ 3,742
------------------------- ---------------------
------------------------- ---------------------
General and administrative
($/BOE) $ 3.81 $ 3.51 $ 3.48 $ 4.54
% Capitalized 34% 32% 31% 27%


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 $0.3 million in the fourth quarter of 2006 compared to $0.5 million in the third quarter and $0.1 million in the fourth quarter of 2005. Interest expense was lower in the fourth quarter than the third quarter of 2006 as proceeds from the issue of common shares in September 2006 were used to pay down debt and fund capital spending. Interest expense is expected to increase in future quarters as a result of higher debt levels associated with the Company's capital program.

Depletion and Depreciation:

Depletion and depreciation was $24.50 per BOE for the year ended December 31, 2006 compared to $28.19 per BOE in 2005. Depletion and depreciation was $21.85 per BOE in the fourth quarter of 2006 compared to $21.62 per BOE in the third quarter and $28.60 per BOE in the fourth quarter of 2005. Depletion and depreciation expense is calculated based on proved reserves only. The recent reserve evaluation completed by AJM Petroleum Consultants increased the ratio of proved to proved plus probable reserves to 65% from 52% in 2005. The higher allocation to proved reserves has resulted in a significant decrease in depletion and depreciation expense.

Asset Retirement Obligation:

As a result of new drilling, the Company incurred $1.1 million in asset retirement obligations in the fourth quarter of 2006 and $3.1 million for the year ended December 31, 2006. Accretion expense was $0.9 million for 2006 compared with $0.4 million for 2005 and was included in depletion and depreciation expense.

Income Taxes:

Anderson Energy is not currently taxable. The Company does not anticipate paying current income tax in 2007. The estimated tax pool balances at December 31, 2006 are summarized below. Tax pool classifications are estimates as some new wells have not yet had their status as exploratory or development confirmed.

The effect of enacted federal and provincial income tax rate reductions resulted in a $1.2 million reduction in the future tax provision in the second quarter. Changes in estimates of when temporary differences would reverse resulted in further reductions in the future tax provision in the fourth quarter.

The subscription receipts financing completed on September 25, 2006, included $15 million of flow-through common shares. The Company committed to use 20% of the gross proceeds to incur Canadian Exploration Expense ("CEE") and 80% to incur Canadian Development Expenses ("CDE"). The Company committed to incur 40% of the CDE in 2006 and the remainder in 2007. As a result of an acceleration of its drilling program in the fourth quarter, the Company incurred 100% of the CDE in 2006 and made the entire renouncement effective for the year ended December 31, 2006 on February 28, 2007. The Company will be using the look back rule for approximately $1.6 million of the CEE commitment and this amount will be spent in 2007. The tax pool estimate below has been reduced for this renouncement to the extent that the capital expenditures have been incurred. The tax pool estimate has also been reduced for the effect of income recorded in 2006 that will not be taxed until 2007.



CEE $ 52 million
CDE $ 40 million
UCC $ 51 million
COGPE $ 19 million
Other $ 25 million
-------------
Total $187 million
-------------
-------------


Cash Flow from Operations:

Cash flow from operations increased by 15% to $29.2 million compared to $25.5 million in 2005. On a per share base, cash flow from operations was $0.58 per share in 2006 compared to $0.66 per share in 2005. For the three months ended December 31, 2006, cash flow from operations was $8.0 million or $0.15 per share, an increase of 36% over the previous quarter of $5.9 million or $0.12 per share, due to improved natural gas prices and higher production. Cash flow from operations in the fourth quarter was still 39% lower than the fourth quarter of 2005 as prices were still significantly lower than at the same time last year.

Earnings:

The Company reported earnings of $0.8 million in the fourth quarter and a loss of $3.5 million for the year ended December 31, 2006 compared to earnings of $1.8 million for the fourth quarter of 2005 and $0.7 million for the year ended December 31, 2005. Significantly lower depletion and depreciation expense in the fourth quarter of 2006 resulted in slightly positive earnings compared to a loss in the previous quarter. However, earnings were still affected by lower prices and higher operating costs in 2006.

The Company's cash flow from operations and earnings are highly sensitive to changes in factors that are beyond its control. An estimate of the Company's sensitivities to changes in commodity prices, exchange rates and interest rates is summarized below:



Sensitivities: Millions Per Share Millions Per Share
------------------------------------------
$0.10/Mcf in price of natural
gas $ 0.8 $ 0.01 $ 0.5 $ 0.01
US $1.00/bbl in the WTI crude
price $ 0.2 $ - $ 0.2 $ -
US $0.01 in the U.S./Cdn
exchange rate $ 0.8 $ 0.01 $ 0.5 $ 0.01
1% in short-term interest rate $ 0.6 $ 0.01 $ 0.4 $ 0.01


Capital Expenditures

The Company spent $22.1 million in capital additions in the fourth quarter and $84.0 million for the year ended December 31, 2006. The breakdown of expenditures is shown below:



Three months
ended Dec 31 Year Ended Dec 31
(thousands of dollars) 2006 2006 2005
----------------------------------
Land, geological & geophysical costs $ 1,466 $ 8,329 $ 4,920
Property acquisitions, net of
dispositions (2,382) (2,868) (88)
Drilling, completion and recompletion 16,231 50,830 43,982
Facilities and well equipment 5,688 24,592 20,216
Office equipment and furniture 15 85 362
Asset retirement costs 1,050 3,065 3,338
----------------------------------
Total $ 22,068 $ 84,033 $ 72,730
----------------------------------
----------------------------------


In addition, a gross-up of capital costs and an associated future income tax liability of $3.2 million were recorded to reflect the fact that the property acquisitions for shares and capitalized stock based compensation costs had minimal tax bases.



Drilling statistics are shown below:

Three months ended Dec 31 Year ended Dec 31
2006 2005 2006 2005
----------------------------------------------------
Gross Net Gross Net Gross Net Gross Net
----------------------------------------------------
Gas 49 34.2 40 19.1 128 70.1 103 54.0
Oil - - 4 2.4 6 4.0 5 2.8
Dry 5 4.4 5 2.5 12 9.7 10 6.3
----------------------------------------------------
Total 54 38.6 49 24.0 146 83.8 118 63.1
----------------------------------------------------
----------------------------------------------------
Success rate (%) 91% 89% 90% 90% 92% 88% 92% 90%


For the fourth quarter of 2006, 78% of the gross wells drilled were in Sylvan Lake and for the year ended December 31, 2006, 65% of the gross wells drilled were in Sylvan Lake.

The Company reported improved finding, development and acquisition costs in 2006. Finding, development and acquisition costs, including future development capital, were $13.34 per BOE on a proved basis and $13.40 per BOE on a proved plus probable basis. This compares to $27.09 per BOE on a proved basis and $18.83 per BOE on a proved plus probable basis in 2005. The improvements reflect the success of the shallow gas drilling program.

Reserves and F,D&A Costs

The Company's reserves were evaluated by AJM Petroleum Consultants in accordance with NI 51-101 as of December 31, 2006. The tables in this section are an excerpt from what will be filed in the Company's Annual Information Form ("AIF') as the Company's NI 51-101 annual required filings.



SUMMARY OF OIL AND GAS RESERVES

Natural Gas
Natural Gas Oil Liquids Total BOE
---------------------------------------------------------------
Gross Net Gross Net Gross Net Gross Net
(Bcf) (Bcf) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MBOE) (MBOE)
Proved
developed
producing 34.3 28.3 357 304 260 191 6,340 5,209
Proved
developed
non
producing 1.1 0.9 11 10 4 3 191 159
Proved
undeveloped 56.7 47.2 125 113 131 88 9,711 8,066
---------------------------------------------------------------
Total proved 92.1 76.4 493 427 395 282 16,242 13,434
Probable 49.6 40.0 343 291 240 171 8,856 7,136
---------------------------------------------------------------
Total proved
plus
probable 141.7 116.4 836 718 635 453 25,098 20,570
---------------------------------------------------------------
---------------------------------------------------------------

Note: Coal Bed Methane and Heavy Oil Reserves are included in the Natural
Gas and Oil categories respectively.


NET PRESENT VALUE BEFORE INCOME TAXES
(AJM DECEMBER 31, 2006 PRICE FORECAST, ESCALATED PRICES):


(thousands of dollars) 0% 5% 10% 15%
-------------------------------------------
Proved developed producing $ 96,515 $ 96,043 $ 88,892 $ 81,849
Proved developed non-producing 4,306 3,220 2,553 2,112
Proved undeveloped 133,998 101,905 77,950 60,096
-------------------------------------------
Total proved 234,819 201,168 169,395 144,057
Probable 174,125 125,772 94,581 73,266
-------------------------------------------
Total proved plus probable $ 408,944 $ 326,940 $ 263,976 $ 217,323
-------------------------------------------
-------------------------------------------


SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
AS OF DECEMBER 31, 2006
FORECAST PRICES AND COSTS

Natural
Oil Gas
-----------------------------------------
WTI Edmonton Hardisty AECO
Cushing City Gate Heavy Gas Price
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl)($Cdn/Mcf)
-----------------------------------------
2007 65.00 72.85 40.35 7.40
2008 69.35 77.75 45.25 8.00
2009 70.75 79.35 50.10 7.90
2010 69.00 77.30 49.69 8.00
2011 67.10 75.15 49.15 8.25
2012 66.25 74.15 48.15 8.40
2013 67.55 75.60 49.60 8.50
thereafter
2%


Edmonton Liquids Prices
--------------------------------
Propane Butane Pentanes Inflation Exchange
Plus Rate Rate
($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) % (US$/$Cdn)
-----------------------------------------------------
2007 47.35 58.30 76.50 - 0.88
2008 50.55 62.20 81.65 2.0 0.88
2009 51.55 63.50 83.30 2.0 0.88
2010 50.25 61.85 81.15 2.0 0.88
2011 48.85 60.10 78.90 2.0 0.88
2012 48.20 59.30 77.85 2.0 0.88
2013 49.15 60.50 79.40 2.0 0.88
thereafter
2%


The future development capital included in the reserve evaluation is $101.5 million for total proved reserves and $164.8 million for total proved plus probable reserves.




CONTINUITY OF GROSS RESERVES
Natural Oil & Natural
Gas Gas Liquids
(Bcf) (Mbbls)
Proved Probable Total Proved Probable Total
------------------------------------------------
Opening Balance
December 31, 2005 51.9 49.2 101.1 933 550 1,483
Net Acquisitions 26.1 (0.1) 26.0 67 34 101
Drilling Activity 16.9 10.0 26.9 52 79 131
Revisions 4.8 (9.5) (4.7) 73 (80) (7)
Production (7.6) - (7.6) (237) - (237)
------------------------------------------------
Closing Balance
December 31, 2006 92.1 49.6 141.7 888 583 1,471
------------------------------------------------
------------------------------------------------

Note: Closing balance for natural gas includes 2.9 Bcf of proved and 3.3 Bcf
of probable Coal Bed Methane reserves.


FINDING, DEVELOPMENT & ACQUISITION COSTS

Finding, Change in Finding,
Development Future Development
& Acquisition Development Net & Acquisition
Costs Costs Total Costs Addition(1) Costs
(thousands) (thousands) (thousands) (MBOE) ($/BOE)
----------------------------------------------------------------
2006 Proved $ 80,883 $ 27,980 $ 108,863 8,159 $ 13.34
2006 Proved
plus
probable 80,883 29,830 110,713 8,263 13.40
2005 Proved 149,619 67,933 217,552 8,030 27.09
2005 Proved
plus
probable 149,619 115,730 265,349 14,092 18.83
3 year
Average
proved 270,948 96,677 367,625 16,944 21.70
3 year
Average
proved 270,948 155,901 426,849 24,801 17.21
plus
probable

(1) Net Additions are defined as gross reserve additions minus gross reserve
revisions


The aggregate of the exploration and development costs incurred in the most recent financial year and the change during the year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. 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.

Share Information

The Company's shares have been listed on the Toronto Stock Exchange since September 7, 2005 under the symbol "AXL". As of December 31, 2006, there were 53.6 million common shares outstanding and 4.8 million stock options outstanding. During 2006, 3.2 million shares were issued under flow-through financing, 1.1 million shares under private placement, 0.9 million shares for property acquisitions and 0.4 million shares were issued under the employee stock option plan. The Company's market capitalization at December 31, 2006 was $208 million. The Company believes the decrease in market capitalization is due to lower natural gas prices which impacted the Company's stock price. The annualized trading turnover ratio was 40%. As of March 14, 2007, there were 53.6 million shares outstanding and 4.8 million stock options outstanding.



Share Price on TSX 2006 2005
-----------------------------

High $ 8.00 $ 10.00
Low $ 3.53 $ 7.00
Close $ 3.88 $ 7.75
Volume 21,340,486 12,021,998

Shares outstanding 53,641,401 47,967,708
Market capitalization at December 31 $ 208,128,636 $ 371,749,737


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 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.

Liquidity and Capital Resources

At December 31, 2006, the Company had outstanding bank loans of $27.6 million and a working capital deficiency of $21.0 million. The Company expects to spend $50 million (net of dispositions) in capital in 2007. These expenditures will be funded from cash flow and available bank lines. The Company is capable of conducting a larger program, however, given the current weak natural gas market, management has elected to proceed with a conservative budget at the start of 2007.

The Company's need for capital will be both short-term and long-term in nature. Short-term capital is required to finance accounts receivable and other similar short-term assets while the acquisition and development of oil and natural gas properties requires larger amounts of long-term capital. The Company increased its bank loan facility from $45 million at December 31, 2005 to $55 million at December 31, 2006. The facility was further increased to $75 million early in 2007. The $20 million increase in the bank line is dedicated to expenditures made in the Sylvan Lake Edmonton Sands shallow gas play. Anderson Energy will prudently use its bank loan facility to finance its operations as required. Anderson Energy anticipates that it will make use of equity financing for any significant expansion in its capital programs.

Contractual Obligations

The Company enters into various contractual obligations in the course of conducting its operations. These obligations include:

- Loan agreement - This 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 Company will be requesting an extension of the revolving period to July 15, 2008 following the filing of its 2006 audited consolidated financial statements.

- Lease for office space - This lease expires on November 30, 2008. Future minimum lease payments are expected to be $799,000 in 2007 and $732,000 in 2008.

- Firm service transportation commitments - The Company has entered into firm service transportation agreements for approximately 16.6 million cubic feet per day of gas sales in central Alberta for various terms expiring up to 2009.

- Flow-through share commitments - The Company committed to incur $15 million of qualifying expenditures by December 31, 2007. The Company has spent $13.4 million to December 31, 2006.

These obligations are described further in other parts of this MD&A and in the notes to the audited consolidated financial statement

Critical Accounting Estimates

The Company's significant accounting policies are disclosed in note 1 to the consolidated financial statements. Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. These accounting policies are discussed below and are included to aid the reader in assessing the critical accounting policies and practices of the Company and the likelihood of materially different results than reported. The Company's management reviews its estimates regularly. The emergence of new information and changed circumstances may result in actual results that differ materially from current estimates.

Proved Oil and Gas Reserves:

Proved oil and gas reserves, as defined by the Canadian Securities Administrators in National Instrument 51-101 with reference to the Canadian Oil and Gas Evaluation Handbook, are those reserves that can be estimated with a high degree of certainty to be recoverable. Determination of reserves is a complex process involving judgments, estimates and decisions based on available geological, engineering, production and any other relevant data. These estimates are subject to material change as economic conditions change and ongoing production and development activities provide new information.

An independent reserve evaluator has prepared the Company's oil and gas reserve estimate. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes, reservoir performance or a change in the Company's development plans. The effect of changes in proved oil and gas reserves on the financial results and financial position of the Company is described below under the heading "Full Cost Accounting" and "Full Cost Accounting Ceiling Test".

Full Cost Accounting:

The Company follows the full cost method of accounting for petroleum and natural gas properties, whereby all costs of exploring for and developing petroleum and natural gas properties and related reserves are capitalized. The capitalized costs are depleted and depreciated using the unit-of-production method based on estimated proved reserves. Reserve estimates can have a significant impact on earnings, as they are a key component in the calculation of depletion and depreciation. A downward revision in a reserve estimate could result in a higher depletion and depreciation charge to earnings. In addition, if net capitalized costs are determined to be in excess of the calculated ceiling, which is based largely on reserve estimates (see "Full Cost Accounting Ceiling Test"), the excess must be written off as an expense charged against earnings. In the event of property dispositions, proceeds are normally deducted from the full cost pool without recognition of gain or loss unless there is a change in the depletion rate of 20% or greater.

Unproved Properties:

Certain costs related to unproved properties are excluded from costs subject to depletion until proved reserves have been determined or their value is impaired. These properties are reviewed quarterly and any impairment is transferred to the costs being depleted. The costs relating to unproved properties are also excluded from the book value subject to the ceiling test measurement.

Full Cost Accounting Ceiling Test:

Petroleum and natural gas assets are evaluated in each reporting period to determine that the carrying amount in a cost centre is recoverable and does not exceed the fair value of the properties in the cost centre.

Impairment is indicated if the carrying value of the oil and gas cost centre is not recoverable by the future undiscounted cash flows. If impairment is indicated, the amount by which the carrying value exceeds the estimated fair value of the oil and gas assets is charged to earnings. The ceiling test is based on estimates of reserves, production rates, petroleum and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could be material.

Asset Retirement Obligations:

The Company is required to provide for future removal and site restoration costs. The Company must estimate these costs in accordance with existing laws, contracts or other policies. These estimated costs are charged to property, plant & equipment and the appropriate liability account over the expected service life of the asset. The estimate of future removal and site restoration costs involves a number of estimates related to timing of abandonment, determination of the economic life of the asset, costs associated with abandonment and site restoration, review of potential abandonment methods and salvage/usage of tangible equipment.

Income Taxes:

The determination of the Company's income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ from that estimated and recorded by management.

Stock-Based Compensation Expense:

In order to recognize stock-based compensation expense, the Company estimates the fair value of stock options granted using assumptions related to interest rates, expected life of the option, volatility of the underlying security and expected dividend yields. These assumptions may vary over time.

Goodwill:

The process of accounting for the purchase of a company results in recognizing the fair value of the acquired company's assets on the balance sheet of the acquiring company. Any excess of the purchase price over fair value is recorded as goodwill. Since goodwill results from the culmination of a process that is inherently imprecise, the determination of goodwill is also imprecise. Goodwill is assessed periodically for impairment. Impairment is indicated if the Company's market capitalization falls below the book value of its equity.

Changes in Accounting Policies

CICA Handbook Section 3855 "Financial Instruments - Recognition and Measurement", Section 3861 "Financial Instruments - Disclosure and Presentation", Section 3865 "Hedges" and Section 1530 "Comprehensive Income" are effective for fiscal years beginning on or after October 1, 2006. These policies deal with the recognition and measurement of financial instruments and comprehensive income. The Company is currently reviewing the standards and does not expect them to have a significant impact on its financial reporting.

Disclosure Controls and Procedures

The Chief Executive Officer and the Chief Financial Officer have evaluated the effectiveness of Anderson Energy's disclosure controls and procedures as of December 31, 2006 and have concluded that such disclosure controls and procedures were effective.

The Chief Executive Officer and the Chief Financial Officer have evaluated the design of Anderson Energy's internal controls over financial reporting as of December 31, 2006 and have concluded that that, if functioning as designed, these internal controls would provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with Canadian GAAP. There were no material changes in the Company's internal controls over financial reporting in the last quarter of the Company's fiscal year.

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, not absolute, assurance that the objectives of the controls 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 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 operations and 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 personal, 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 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 in its three core resource plays, Sylvan Lake Edmonton Sands, Horseshoe Canyon Coal Bed Methane and northeast BC. With the resumption of production through the Focus Energy Trust Sylvan Lake gas plant in the third quarter, 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's 2007 average production guidance is 5,000 to 5,400 BOED of production, a 22% to 31% increase over 2006 production. Risks associated with this guidance include gas plant capacity, regulatory issues, weather problems and access to industry services.

The recent announcements by the federal government on changes in income trust taxation may have a positive impact on the Company, likely making the acquisition market economic to pursue. The Company is reviewing the potential of such acquisitions in its core areas.



SELECTED QUARTERLY INFORMATION
(in thousands, except per share
amounts)
Q4 2006 Q3 2006 Q2 2006 Q1 2006
---------------------------------------
Oil and gas revenue before royalties $ 16,820 $ 14,651 $ 15,452 $ 16,889
Cash flow from operations $ 7,996 $ 5,873 $ 6,728 $ 8,604
Cash flow from operations per share
Basic $ 0.15 $ 0.12 $ 0.14 $ 0.18
Diluted $ 0.15 $ 0.12 $ 0.13 $ 0.17
Earnings (loss) $ 846 $ (1,509) $ (1,675) $ (1,196)
Earning (loss) per share
Basic $ 0.02 $ (0.03) $ (0.03) $ (0.02)
Diluted $ 0.02 $ (0.03) $ (0.03) $ (0.02)
Capital expenditures $ 22,068 $ 11,592 $ 16,653 $ 33,720
Daily sales
Natural gas (Mcfd) 21,075 19,621 21,664 20,799
Liquids (bpd) 692 736 549 614
BOE (BOED) 4,205 4,006 4,160 4,081
Average prices
Natural gas ($/Mcf) $ 6.82 $ 5.71 $ 6.05 $ 7.40
Liquids ($/bbls) $ 51.09 $ 62.14 $ 68.19 $ 51.15
BOE ($/BOE) $ 42.62 $ 39.41 $ 40.50 $ 45.41


Q4 2005 Q3 2005 Q2 2005 Q1 2005
---------------------------------------
Oil and gas revenue before royalties $ 22,894 $ 12,147 $ 6,646 $ 5,266
Cash flow from operations $ 13,187 $ 6,745 $ 2,941 $ 2,581
Cash flow from operations per share
Basic $ 0.28 $ 0.18 $ 0.09 $ 0.08
Diluted $ 0.27 $ 0.17 $ 0.09 $ 0.07
Earnings (loss) $ 1,762 $ 543 $ (801) $ (773)
Earning (loss) per share
Basic $ 0.04 $ 0.01 $ (0.02) $ (0.02)
Diluted $ 0.04 $ 0.01 $ (0.02) $ (0.02)
Capital expenditures $ 25,635 $ 14,960 $ 11,589 $ 20,546
Daily sales
Natural gas (Mcfd) 18,785 11,991 9,623 8,165
Liquids (bpd) 577 250 50 28
BOE (BOED) 3,708 2,249 1,653 1,389
Average prices
Natural gas ($/Mcf) $ 11.39 $ 9.68 $ 7.28 $ 6.96
Liquids ($/bbls) $ 53.56 $ 61.97 $ 54.59 $ 52.34
BOE ($/BOE) $ 66.05 $ 58.49 $ 43.98 $ 41.96


SELECTED ANNUAL INFORMATION
Years ended December 31 2006 2005 2004
-------------------------------
Total oil and gas revenues (thousands) $ 63,812 $ 46,953 $ 13,766
Total oil and gas revenues, net of royalties
(thousands) $ 50,507 $ 36,780 $ 10,754
Earnings (loss) (thousands) $ (3,534) $ 731 $ (1,619)
Earnings (loss) per share (basic) $ (0.07) $ 0.02 $ (0.05)
Earnings (loss) per share (diluted) $ (0.07) $ 0.02 $ (0.05)
Total assets (thousands) $ 317,364 $ 269,412 $ 124,184
Total long-term debt (thousands) $ 27,627 $ 11,368 $ -


Advisory

Certain information regarding Anderson Energy Ltd. in this press 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 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 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's website (www.andersonenergy.ca). Furthermore, the forward-looking statements contained in this annual report are made as at the date of this press release and Anderson Energy does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

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



ANDERSON ENERGY LTD.
Consolidated Balance Sheets
December 31, 2006 and 2005

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

(stated in thousands of dollars) 2006 2005
----------------------------------------------------------------------------

Assets

Current assets:
Cash $ 11 $ 510
Accounts receivable and accruals 28,885 31,303
Prepaid expenses and deposits 1,968 1,562
----------------------------------------------------------------------------
30,864 33,375

Property, plant and equipment (note 2) 272,180 221,717

Goodwill (note 10) 14,320 14,320

----------------------------------------------------------------------------
$ 317,364 $ 269,412
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities and Shareholders' Equity

Current liabilities:
Accounts payable and accruals $ 51,890 $ 46,420
Capital taxes payable - 184
----------------------------------------------------------------------------
51,890 46,604

Bank loan (note 4) 27,627 11,368

Asset retirement obligations (note 3) 14,905 11,299

Future income taxes (note 6) 17,012 16,073
----------------------------------------------------------------------------
111,434 85,344

Shareholders' equity:
Share capital (note 5) 208,994 184,315
Contributed surplus (note 5) 820 103
Deficit (3,884) (350)
----------------------------------------------------------------------------
205,930 184,068

----------------------------------------------------------------------------
$ 317,364 $ 269,412
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


ANDERSON ENERGY LTD.
Consolidated Statements of Operations and Deficit
Years ended December 31, 2006 and 2005

(stated in thousands of dollars,
except per share amounts) 2006 2005
----------------------------------------------------------------------------

Revenues
Oil and gas sales $ 63,812 $ 46,953
Royalties
(net of ARTC of $500 in 2006, $500 in 2005) (13,305) (10,173)
Interest income 99 279
----------------------------------------------------------------------------
50,606 37,059
Expenses
Operating 14,934 7,480
General and administrative 5,226 3,742
Interest and other financing charges 1,607 203
Depletion, depreciation and accretion 37,723 23,570
----------------------------------------------------------------------------
59,490 34,995

----------------------------------------------------------------------------
Earnings (loss) before taxes (8,884) 2,064

Taxes (note 6)
Capital taxes - 283
Future income taxes (reduction) (5,350) 1,050
----------------------------------------------------------------------------
(5,350) 1,333

----------------------------------------------------------------------------
Earnings (loss) for the year (3,534) 731

Deficit, beginning of year (350) (1,081)

----------------------------------------------------------------------------
Deficit, end of year $ (3,884) $ (350)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Earnings (loss) per share
Basic $ (0.07) $ 0.02
Diluted $ (0.07) $ 0.02
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


ANDERSON ENERGY LTD.
Consolidated Statements of Cash Flows
Years ended December 31, 2006 and 2005

(stated in thousands of dollars) 2006 2005
----------------------------------------------------------------------------

Cash provided by (used in):

Operations
Earnings (loss) for the year $ (3,534) $ 731
Items not involving cash
Depletion, depreciation and accretion 37,723 23,570
Future income taxes (reduction) (5,350) 1,050
Stock-based compensation 362 103
Asset retirement expenditures (405) (310)
Changes in non-cash working capital
Accounts receivable and accruals 1,708 (3,370)
Prepaid expenses and deposits (576) (311)
Accounts payable and accruals 2,787 3,806
Capital taxes payable (184) 164
----------------------------------------------------------------------------
32,531 25,433

Financing
Increase in bank loan 16,259 11,368
Issue of common shares 20,993 30,412
----------------------------------------------------------------------------
37,252 41,780

Investments
Additions to property, plant and equipment (86,249) (70,517)
Proceeds on sale of properties 12,404 1,125
Acquisition of Aquest Energy (note 10) - (1,042)
Payment of Aquest Energy liabilities assumed (note 10) - (26,439)
Changes in non-cash working capital
Accounts receivable and accruals 710 (20,677)
Prepaid expenses and deposits 170 (974)
Accounts payable and accruals 2,683 22,579
----------------------------------------------------------------------------
(70,282) (95,945)

----------------------------------------------------------------------------
Decrease in cash (499) (28,732)

Cash, beginning of year 510 29,242
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Cash, end of year $ 11 $ 510
----------------------------------------------------------------------------

See accompanying notes to consolidated financial statements


ANDERSON ENERGY LTD.
Notes to the Consolidated Financial Statements
Years ended December 31, 2006 and 2005

(Tabular amounts in thousands of dollars, unless otherwise stated)
----------------------------------------------------------------------------


Anderson Energy Ltd. ("Anderson Energy" or "the Company") was incorporated under the laws of the province of Alberta on January 30, 2002. Anderson Energy is engaged in the acquisition, exploration and development of oil and gas properties in western Canada. These consolidated financial statements include the accounts of Anderson Energy Ltd. and its wholly owned subsidiaries and have been prepared by management in accordance with accounting principles generally accepted in Canada. Management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenue and expenses during the reported period. Actual results could differ from these estimates.

1. Significant Accounting Policies

(a) Cash and short-term investments

Cash is defined as cash in the bank, less outstanding cheques.

(b) Capital assets

The Company follows the full cost method of accounting for oil and gas properties. Under this method, all costs relative to the exploration for and development of oil and gas reserves are capitalized. Capitalized costs include lease acquisitions, geological and geophysical costs, lease rentals on non-producing properties, costs of drilling productive and non-productive wells and plant and production equipment costs. Proceeds received from disposals of oil and gas properties and equipment are credited against capitalized costs unless the disposal would alter the rate of depletion and depreciation by more than 20%, in which case a gain or loss on disposal is recorded.

Oil and gas capitalized costs are depleted and depreciated using the unit of production method based on total proved reserves before royalties. Natural gas sales and reserves are converted to equivalent units of crude oil using their relative energy content. The costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations until it is determined whether or not proved reserves are attributable to the property or impairment occurs. Office equipment and furniture are being depreciated over their useful lives using the declining balance method at rates between 20% and 30% per annum.

A detailed impairment calculation is performed when events or circumstances indicate a potential impairment of the carrying amount of oil and gas assets may have occurred, and at least annually. An impairment loss is recognized when the carrying amount of a cost centre is not recoverable and exceeds its fair value. The carrying amount is assessed to be recoverable when the sum of the undiscounted cash flows expected from the proved reserves plus the cost of unproved interests, net of impairments, exceeds the carrying amount of the cost centre. When the carrying amount is assessed not to be recoverable, an impairment loss is recognized to the extent that the carrying amount of the cost centre exceeds the sum of the discounted cash flows from proved and probable reserves plus the cost of unproved interests, net of impairments, of the cost centre. The cash flows are estimated using expected future product prices and costs and are discounted using a risk-free interest rate.

(c) Asset retirement obligations

The Company records the fair value of asset retirement obligations as a liability in the period in which it incurs a legal obligation to restore an oil and gas property, typically when a well is drilled or equipment is put in place. The associated asset retirement costs are capitalized as part of the carrying amount of capital assets and depleted and depreciated using the unit of production method based on total proved reserves before royalties. Subsequent to the initial measurement of the obligations, the obligations are adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation.

(d) Goodwill

Goodwill is the excess purchase price over the fair value of identifiable assets and liabilities acquired in a business combination. Goodwill is not amortized and is tested for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired. To assess impairment, the fair value of the Company is determined and compared to the book value of the Company. If the fair value of the Company is less than the book value, then a second test is performed to determine the amount of the impairment. The amount of the impairment is determined by deducting the fair value of the individual assets and liabilities from the fair value of the Company to determine the implied fair value of goodwill. An impairment loss is recognized for the excess of the carrying value of goodwill over the implied fair value.

(e) Income taxes

The Company follows the asset and liability method of accounting for income taxes. Under this method, income tax assets and liabilities are recognized for the estimated tax consequences attributable to differences between the amounts reported in the financial statements and their respective tax bases, using income tax rates enacted at the balance sheet date. The effect of a change in rates on future income tax assets and liabilities is recognized in the period that the change occurs.

(f) Flow-through shares

The resource expenditure deductions for income tax purposes related to exploratory and development activities funded by flow-through share arrangements are renounced to investors in accordance with income tax legislation. An estimate of the additional tax liability to be incurred and included in the future tax provision is recognized and charged to share capital at the time the resource expenditure deductions for income tax purposes are renounced to investors.

(g) Stock-based compensation plans

The Company accounts for stock options granted to employees and directors using the the fair value method of accounting for stock-based compensation plans. Under this method, the Company recognizes compensation expense, with a corresponding increase to contributed surplus, based on the fair value of the options over the vesting period of the grant. The Company uses a Black-Scholes option pricing model to determine the fair value of options at the date of grant. When exercised, the consideration paid together with the amount previously recognized in contributed surplus is recorded as an increase to share capital.

(h) Revenue recognition

Revenue from the sale of oil and gas is recognized when title passes from the Company to the purchaser.

(i) Commodity contracts

The Company may enter into derivative financial instruments and physical fixed price sales contracts to manage its commodity price exposure. No contracts are entered into for trading or speculative purposes. When the Company enters into a derivative financial instrument contract, it formally assesses both at the contract's inception and on an ongoing basis whether the contract is highly effective in offsetting changes in cash flows of the hedged item. These derivative financial instrument contracts, accounted for as hedges, are not recognized on the balance sheet. Realized gains and losses on these contracts are recognized in revenues in the same period in which the revenues associated with the hedged transactions are recognized. Derivative financial instruments that do not qualify as effective hedges for accounting purposes are recorded on a mark-to-market basis with the resulting gains or losses taken into income.

(j) Interests in joint operations

A substantial portion of the Company's oil and gas exploration and development activities are conducted jointly with others, and accordingly, the consolidated financial statements reflect only the Company's proportionate interest in such activities.

(k) Per share amounts

Basic per share amounts are calculated using the weighted average number of common shares outstanding during the period. Diluted per share amounts reflect the potential dilution that could occur if securities or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments. Under the treasury stock method, only options for which the exercise price is less than the market value impact the dilution calculations.



2. Property, plant and equipment

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

2006 2005
----------------------------------------------------------------------------
Cost $ 342,529 $ 255,289
Less accumulated depletion and depreciation (70,349) (33,572)
----------------------------------------------------------------------------
Net book value $ 272,180 $ 221,717
----------------------------------------------------------------------------
----------------------------------------------------------------------------


At December 31, 2006, unproved property costs of $21.2 million (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 $101.5 million (2005 - $73.5 million) have been included for depletion, depreciation and impairment test calculations.

For the year ended December 31, 2006, $3.2 million (2005 - $1.7 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 December 31, 2006. The future commodity prices used in the ceiling test were based on commodity price forecasts of the Company's independent reserve engineers adjusted for differentials specific to the Company's reserves. The natural gas price at AECO was estimated to be $7.40 per thousand cubic feet in 2007, $8.00 in 2008, $7.90 in 2009, $8.00 in 2010 and $8.25 in 2011. After 2011, only inflationary growth was considered. Natural gas liquids prices were tied to crude oil prices based on historical trends and analysis. The WTI crude price was forecast to be US$65.00 per barrel in 2007, US$69.35 per barrel in 2008, US$70.75 per barrel in 2009, US$69.00 per barrel in 2010, US$67.10 in 2011 and US$66.25 in 2012. After 2012, only inflationary growth was considered.

3. Asset retirement obligations

The Company estimates the total undiscounted cash flows required to settle its asset retirement obligations is approximately $27.7 million (2005 - $20.6 million), including expected inflation of 2% (2005 - 2%) per annum. The majority of the costs will be incurred between 2007 and 2019. A credit adjusted risk-free rate of 8% (2005 - 7.5%) was used to calculate the fair value of the asset retirement obligations.



A reconciliation of the asset retirement obligations is provided below:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
December 31, December 31,
2006 2005
----------------------------------------------------------------------------
Balance, beginning of year $ 11,299 $ 2,094
Liabilities incurred during year 3,065 3,338
Liabilities assumed on Aquest Energy acquisition
(note 10) - 5,822
Liabilities settled in year (405) (310)
Accretion expense 946 355
----------------------------------------------------------------------------
$ 14,905 $ 11,299
----------------------------------------------------------------------------
----------------------------------------------------------------------------


4. Bank loan

In May 2006, the Company renewed its revolving credit facility with a Canadian bank, increasing the borrowing base to $55 million. In February 2007, a further increase to $75 million was approved by the bank. The additional $20 million in revolving credit facility is a development tranche available expressly for investments in Sylvan Lake/Edmonton Sands development. 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.



5. Share capital and contributed surplus

Issued share capital
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Number of shares
---------------------------------
Common Amount
Class A Class B shares (thousands)
----------------------------------------------------------------------------

Balance at December 31, 2004 875,000 32,689,667 - $ 102,389
Stock options exercised - 60,000 - 240
Tax effect of flow-through
share renouncements - - - (2,293)
Conversion to common shares (875,000)(32,749,667) 33,624,667 -
----------------------------------------------------------------------------
- - 33,624,667 100,336
---------------------
---------------------
Issued on Aquest Energy acquisition (note 10) 9,656,147 53,109
Issue of common shares(1) 3,100,000 20,150
Issue of flow-through common shares(1) 1,250,000 10,000
Share issue costs - (1,831)
Future tax effect of share issue costs - 699
Stock options exercised 336,894 1,852
----------------------------------------------------------------------------
Balance at December 31, 2005 47,967,708 184,315
Issued on property acquisitions 943,791 6,768
Issued of private placement common shares (2) 1,091,703 5,000
Issue of flow-through common shares (2) 3,191,490 15,000
Share issue costs - (950)
Tax effect of share issue costs 299
Stock options exercised 446,709 1,943
Transferred from contributed surplus on stock
option exercise 1
Tax effect of flow-through share renouncements (3,382)
----------------------------------------------------------------------------
Balance at December 31, 2006 53,641,401 $ 208,994
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes 7,000 common shares and 142,750 flow-through shares issued to
management, directors and employees
(2) Includes 1,091,703 common shares and 255,320 flow-through shares issued
to management and directors


Pursuant to a plan of arrangement each Class A and B shareholder received one common share for each Class A or B share held.

Flow-through shares

Under flow-through share agreements entered into in 2004, the Company committed to incur $6,003,000 of qualifying expenditures by December 31, 2005. The renouncements were made on February 28, 2005 with an effective date of December 31, 2004.

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 on February 28, 2006 with an effective date of December 31, 2005.

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 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.



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 years ended December 31, 2005 and
2006 are as follows:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Number of options

Balance at December 31, 2004 3,411,700
Granted 961,465
Assumed on acquisition of Aquest Energy (note 10) 964,300
Exercised (396,894)
Expirations and cancellations (761,216)
----------------------------------------------------------------------------
Balance at December 31, 2005 4,179,355
Granted 1,544,100
Exercised (446,709)
Expirations and cancellations (446,340)
----------------------------------------------------------------------------
Balance at December 31, 2006 4,830,406
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The outstanding options at December 31, 2006 had an average exercise price of $4.89 per share (2005 - $4.95 per share) and a weighted average remaining contractual life of five years (2005 - six years); 2,897,273 (2005 - 3,025,822) 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 (2005 - $2.00 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% (2005 - 3.3%), expected option life of four years, expected volatility of between 25% to 40% and a dividend yield of 0%.

Per share amounts

During the year December 31, 2006 there were 50,164,782 weighted average shares outstanding (2005 - 38,371,995). On a diluted basis, there were 50,247,526 weighted average shares outstanding (2005 - 39,309,036) after giving effect to dilutive stock options.



Contributed surplus

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Amount
----------------------------------------------------------------------------
Balance at December 31, 2004 $ -
Stock-based compensation 103
----------------------------------------------------------------------------
Balance at December 31, 2005 103
Stock-based compensation 718
Transferred from contributed surplus on stock option exercise (1)
----------------------------------------------------------------------------
Balance at December 31, 2006 $ 820
----------------------------------------------------------------------------
----------------------------------------------------------------------------

6. Taxes

The temporary differences that gave rise to the Company's future tax
liabilities (assets) were as follows:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
2006 2005
----------------------------------------------------------------------------
Future income tax liabilities (assets):
Property, plant and equipment in excess
of tax basis $ 16,912 $ 16,827
Asset retirement obligations (4,358) (3,821)
Share issue expenses (1,055) (1,217)
Current income deferred 5,513 4,284
----------------------------------------------------------------------------
$ 17,012 $ 16,073
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The provision for income taxes differs from the result that would have been
obtained by applying the combined federal and provincial tax rates to
earnings before income taxes. The difference results from the following
items:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
2006 2005
----------------------------------------------------------------------------

Earnings (loss) before income tax $ (8,884) $ 2,064
Combined federal and provincial tax rates 34.61% 37.92%
----------------------------------------------------------------------------
Expected income tax expense (recovery) (3,075) 783
Increase (decrease) in income taxes resulting from:
Non-deductible crown payments - 1,458
Federal resource allowance - (1,036)
Capital taxes - 282
Changes in expected future tax rates and other (2,275) (154)
----------------------------------------------------------------------------
Provision for (recovery of) income taxes $ (5,350) $ 1,333
----------------------------------------------------------------------------
----------------------------------------------------------------------------

In May 2006, the Company recorded a $1.2 million future tax benefit related
to enacted federal and provincial income tax rate reductions. In December
2006, the Company recorded a $1.1 million future tax benefit related to a
change in its expected future tax rate.

7. Cash payments

The following cash payments were paid (received):

----------------------------------------------------------------------------
----------------------------------------------------------------------------
December 31, December 31,
2006 2005
----------------------------------------------------------------------------

Interest paid $ 1,699 $ 231
Interest received (68) (309)
Taxes paid 294 118

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


8. Financial instruments

The carrying value of financial instruments included in the consolidated balance sheets approximate their fair value. Financial instruments include cash, accounts receivable and accruals, deposits, accounts payable and accruals, capital taxes payable and bank loans. The carrying value of accounts receivable and accruals, deposits and accounts payable and accruals approximate their fair value due to their demand nature or relatively short periods to maturity. The fair value of the bank loan approximates its carrying value as it bears interest at a floating rate.

A substantial portion of the Company's accounts receivable are with customers and joint venture partners in the oil and gas industry and are subject to normal industry credit risks. Purchasers of the Company's natural gas and liquids are subject to internal credit review to minimize the risk of non-payment.

The Company is exposed to credit risk associated with possible non-performance by counterparties to derivative financial instrument contracts. The Company believes these risks to be minimal as the counterparties are major financial institutions.

The Company is exposed to foreign currency fluctuations as natural gas and liquids prices received are referenced to United States dollar denominated prices.



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


The mark-to-market value of the natural gas financial swap contracts at December 31, 2006 was $2.2 million. The actual gains realized subsequent to December 31, 2006 were $1.2 million.

9. Related party transactions

At December 31, 2006, accounts payable includes $45,000 due to a company controlled by a director of the Company. The director was previously a director of Aquest Energy Ltd. ("Aquest Energy"), 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.

10. Acquisition of Aquest Energy Ltd.

On June 27, 2005, the Company entered into an arrangement agreement with Aquest Energy, a publicly traded oil and gas company. Pursuant to the arrangement, Anderson Energy acquired all of the outstanding shares of Aquest Energy for consideration of 0.31 Anderson Energy shares for each Aquest Energy share, for total consideration of 9.6 million Anderson Energy common shares valued at $53.1 million before transaction costs. The arrangement was approved by the shareholders and received regulatory approval on August 31, 2005 and the transaction closed on September 1, 2005. The acquisition has been accounted for using the purchase method of accounting whereby the assets and liabilities of Aquest Energy were recorded at fair market values at September 1, 2005 and the operating results were included in the consolidated financial statements from September 1, 2005. The fair value of the assets acquired and the liabilities assumed on September 1, 2005 are as follows:



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

Current assets $ 8,381
Bank loan (20,947)
Accounts payable and accruals (13,873)
Property, plant and equipment 84,794
Goodwill 14,320
Asset retirement obligations (5,822)
Future income taxes (12,702)
----------------------------------------------------------------------------
$ 54,151
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Consideration paid
9,656,147 common shares $ 53,109
Transaction costs 1,042
----------------------------------------------------------------------------
$ 54,151
----------------------------------------------------------------------------
----------------------------------------------------------------------------


11. Commitments

The Company has entered into an agreement to lease office space until November 2008. Future minimum lease payments are expected to be $799,000 in 2007 and $732,000 in 2008.

The Company entered into firm service transportation agreements for approximately 16.6 million cubic feet per day of gas sales in central Alberta for various terms expiring up to 2009.

Under flow-through share agreements entered into in 2006, the Company committed to incur $15 million in qualifying expenditures by December 31, 2007. The Company has spent $13.4 million to December 31, 2006.



Corporate Information

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

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


Head Office
700 Canterra Tower
400 3rd Avenue S.W.
Calgary, Alberta
Canada T2P 4H2
Phone (403) 262-6307
Fax (403) 261-2792

Auditors
KPMG LLP
Calgary, Alberta

Independent Engineers
AJM Petroleum Consultants

Legal Counsel
Bennett Jones LLP

Registrar & Transfer Agent
Valiant Trust Company

Stock Exchange
The Toronto Stock Exchange
Symbol AXL

Abbreviations used:

bbls - barrels
bpd - barrels per day
Mbbls - thousand barrels
BOE - barrels of oil equivalent
BOED - barrels of oil equivalent per day
GJ - gigajoule
MBOE - thousand barrels of oil equivalent
MMBOE - million barrels of oil equivalent
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 and Chief Executive Officer
    (403) 206-6000
    Website: www.andersonenergy.ca