Anderson Energy Ltd.
TSX : AXL

Anderson Energy Ltd.

March 18, 2008 09:00 ET

Anderson Energy Ltd. Announces 2007 Fourth Quarter and Year End Results

CALGARY, ALBERTA--(Marketwire - March 18, 2008) - 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, 2007.

Highlights:

- Funds from operations in the fourth quarter of 2007 were $12.6 million ($0.14/share), up 101% over the third quarter of 2007 and 57% over the fourth quarter of 2006.

- Production averaged 7,095 BOED for the fourth quarter of 2007, 69% higher than the same period in 2006. For the year ended December 31, 2007, production averaged 5,328 BOED, a 30% increase over 2006. The unusually wet weather conditions in the summer and fall had a negative impact on production. With frozen ground conditions, the Company was able to tie-in 37 wells in the last six weeks of the year and add over 1,700 BOED of production, achieving our exit target of 8,000 BOED. Current production is approximately 7,800 BOED. Behind pipe production capability is approximately 2,100 BOED.

- Finding, development and acquisition ("FD&A") costs including future development capital for 2007 were $18.03 per BOE total proved and $14.39 per BOE total proved plus probable (excluding revisions), and $19.55 per BOE total proved and $16.71 per BOE total proved plus probable (including revisions).

- Year end 2007 reserves were 28.9 MMBOE total proved and 39.9 MMBOE total proved plus probable, 78% and 59% increases respectively over 2006.

- The Company replaced production by a factor of 7.5 times for total proved reserves and 8.6 times for total proved plus probable reserves. Reserves life indices were 9.9 years total proved and 13.7 years total proved plus probable using 2007 year end production.

- On September 1, 2007, the Company completed the acquisition of oil and natural gas assets in its core area of Greater Sylvan Lake for cash consideration of $117.6 million. The acquisition was financed through the issuance of 25.7 million common shares priced at $3.90 per share for net proceeds of approximately $94.7 million and existing credit facilities.

- In the fourth quarter of 2007, the Company drilled 40 gross (32 net) wells with a success rate of 93%. In 2007, the Company drilled 122 gross (84.7 net) wells with a success rate of 91%.

- The Company completed its largest and most successful quarterly drilling program in the first quarter of 2008 with 71 gross (56 net) Edmonton Sands wells drilled.

- The Company's year end drilling inventory was 1,161 gross (585 net) locations, with the Edmonton Sands project representing 85% of these locations.



Financial and Operating Highlights

Three months ended % Year ended %
December 31 Change December 31 Change
---------------------- ------------------------
2007 2006 2007 2006
---- ---- ---- ----
Financial
(thousands of
dollars, except
share
data)

Total oil and
gas
revenue $ 27,775 $ 16,820 65% $ 83,585 $ 63,812 31%
Funds from
operations $ 12,564 $ 7,996 57% $ 36,414 $ 29,201 25%
Per common
share
(basic and
diluted) $ 0.14 $ 0.15 (7%) $ 0.54 $ 0.58 (7%)

Earnings (loss) 4,867 846 475% 2,184 (3,534) 162%
Per common
share
(basic and
diluted) $ 0.06 $ 0.02 200% $ 0.03 $ (0.07) 143%

Field capital
expenditures 30,180 23,044 31% 84,569 83,480 1%
Acquisitions,
net of
dispositions 120 (2,382) 105% 126,564 (2,868) 4513%
Debt, net of
working
capital 96,832 48,653 99%
Shareholders'
equity 334,452 205,930 62%
Average shares
outstanding
(thousands)
Basic 87,294 53,641 63% 67,794 50,165 35%
Diluted 87,294 53,681 63% 67,847 50,165 35%
Ending shares
outstanding
(thousands) 87,294 53,641 63%

Operating
(6 Mcf:1bbl
conversion)

Average daily
sales
Natural gas
(Mcfd) 35,672 21,075 69% 26,942 20,787 30%
Oil and NGL
(bpd) 1,150 692 66% 837 648 29%
Barrels of oil
equivalent
(BOED) 7,095 4,205 69% 5,328 4,113 30%
Average sales
price
Natural gas
($/Mcf) 6.09 6.82 (11%) 6.48 6.50 -
Oil and NGL
($/BOE) 72.28 51.09 41% 63.12 57.88 9%
Barrels of oil
equivalent
($/BOE) 42.55 43.48 (2%) 42.98 42.50 1%
Royalties
($/BOE) 7.89 7.68 3% 8.10 8.86 (9%)
Operating costs
($/BOE) 11.71 10.30 14% 11.70 9.95 18%
Operating
netbacks
($/BOE) 22.95 25.50 (10%) 23.18 23.69 (2%)
Reserves
Natural gas
(MMcf)
Proved 159,261 92,125 73%
Proved plus
probable 219,099 141,762 55%
Crude oil and
NGL (Mbbls)
Proved 2,350 888 165%
Proved plus
probable 3,372 1,471 129%
Finding,
development
and acquisition
costs
Proved 19.55 13.30 47%
Proved plus
probable 16.71 13.36 25%

Net asset value
($/share) 5.17 4.52 14%
Wells drilled
(gross) 40 54 (26%) 122 146 (16%)
Undeveloped
land
(thousands of
acres)
Gross 316 378 (16%)
Net 138 188 (27%)


2007 OPERATIONS HIGHLIGHTS

In 2007, Anderson Energy completed two acquisitions in the Greater Sylvan Lake area: one for $9.2 million that closed on June 29, 2007 and another for $117.6 million that was completed on September 1, 2007. Both of these acquisitions fit our strategy of adding to our production base and growing our opportunity base with additional drilling potential in the Edmonton Sands and other natural gas horizons. In 2007, the Company completed two "bought deal" equity financings: a $34.5 million common share financing that closed on April 24, 2007 and a $100.2 million subscription receipts financing that closed on August 31, 2007. These financings were used to finance the acquisitions and drill more Edmonton Sands wells.

For the year ended December 31, 2007, the Company averaged 5,328 BOED of production with fourth quarter production averaging 7,095 BOED. The fourth quarter reflects a full quarter of production from the assets acquired in the September 2007 acquisition. The unusually wet weather conditions in the summer and fall had a negative impact on the Company, increasing our drilling and tie-in costs and delaying our operations. With frozen ground conditions, seven pipeline crews and three drilling rigs were deployed enabling the Company to tie-in 37 wells in the last six weeks of the year and add over 1,700 BOED of production, achieving our exit target of 8,000 BOED. Average annual production was 30% higher than in 2006. Current production is 7,800 BOED with behind pipe capability of approximately 2,100 BOED. The Company's funds from operations were $36.4 million and earnings were $2.2 million in 2007 as compared to funds from operations of $29.2 million and a loss of $3.5 million in 2006.

Capital expenditures were $211.1 million in 2007 of which $84.6 million were field capital expenditures, compared to $83.5 million of field capital expenditures in 2006.

During the fourth quarter of 2007, the Company drilled 40 gross (32 net) wells with a success rate of 93%, of which 33 gross (30 net) were Edmonton Sands wells. Third party operated Horseshoe Canyon Coal Bed Methane ("CBM") drilling was 5 gross (1.2 net) wells drilled in the fourth quarter.

Capital spending in the quarter was $30.3 million of which $17.5 million was spent on drilling and completion expenditures and $11.9 million was spent on facility expenditures.

In 2007, the Company drilled 122 gross (84.7 net) wells with a success rate of 91%. During 2007, the Company drilled 86 gross (74.6 net) gas wells in the Edmonton Sands project and participated in 21 gross (4.4 net) Horseshoe Canyon CBM gas wells.

RESERVES AND FINDING, DEVELOPMENT AND ACQUISITION COSTS

The Company's reserves are evaluated independently by AJM Petroleum Consultants ("AJM") in accordance with National Instrument 51-101. In 2007, Anderson Energy increased its total proved reserves by 78% and total proved plus probable reserves by 59%. The Company replaced 2007 production by a factor of 7.5 times for total proved reserves and 8.6 times for total proved plus probable reserves. The Company's reserve life indices, using year end production, are 9.9 years for total proved and 13.7 years for total proved plus probable. Reserve additions and revisions for 2007 are shown in the following table.



CHANGES IN GROSS RESERVES (MBOE)
Total Proved plus
Total Proved Probable
-------------------------------

Opening reserves at December 31, 2006 16,242 25,098
-------------------------------
Additions 7,205 7,074
Acquisitions and dispositions 8,622 12,367
Revisions (1,231) (2,706)
Production (1,945) (1,945)
-------------------------------
Net Change 12,651 14,790
-------------------------------
Ending reserves at December 31, 2007 28,893 39,888
-------------------------------
-------------------------------


Negative revisions were almost entirely the result of changes in the undeveloped reserves booking methodology in the extremities of the Edmonton Sands fairway in the far northwest and southeast. Other negative revisions were in northeast BC, where higher costs and a lower pricing outlook resulted in some future drilling locations becoming uneconomic. Some of the negative revisions were offset by positive revisions in Sylvan Lake North, Pembina Bigoray, Cooking Lake and Teepee.

FD&A costs including future development capital were 25% higher on a total proved plus probable basis than in 2006 due to the future development capital associated with the $117.6 million acquisition in September 2007 and the negative revisions. FD&A expenditures used in this calculation were $209.1 million. Total organic proved plus probable FD&A costs including future development capital were similar to 2006. The Company's future development capital as of December 31, 2007 was $177.8 million total proved and $235.4 million total proved plus probable.



2007 FD&A COSTS
($ PER BOE):
Total Proved Plus
Total Proved Probable
-------------------------------
Additions only 18.03 14.39
Additions plus revisions 19.55 16.71
Component related to change in future
development
capital 5.23 4.22


More detail on FD&A and FD&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, 2007 is outlined below:



(thousands of dollars except share data)

Pretax proved plus probable reserves
NPV10% (1) $532,455

Undeveloped land (2) 15,980

Debt, net of working capital (96,832)
---------
Total $451,603
---------
Number of common shares (thousands) 87,294

Net asset value per share (3) $5.17

(1) Based on an independent evaluation by AJM Petroleum Consultants
effective December 31, 2007.
(2) Based on an independent evaluation by Seaton-Jordan & Associates Ltd.
effective December 31, 2007. The Company has 316,446 gross
(137,987 net) acres of undeveloped land where reserves have not been
assigned.
(3) Basic and fully diluted.


The 2008 gas price used in AJM's price forecast is $6.90 per Mcf at AECO. The net asset value at the 2007 year end is $0.65 per share higher than reported at the 2006 year end.

OUTLOOK

In 2007, with the reduced drilling levels in western Canada, we started to see a reduction in the cost of doing business. The Company does most of its engineering design work with in-house employees and was able to engineer permanent cost savings through a redesign of the Edmonton Sands drilling and completion operations. The average cost to drill and complete an Edmonton Sands gas well in 2007 was $352,000, compared to $454,000 per well two years ago. In the first quarter of 2008, drilling and completion costs were approximately $285,000 per well, a 19% reduction, achieved primarily through the engineering design changes. The drilling rig day rate in the first quarter of 2008 was only 2% lower than in 2007. The impact of the cost savings achieved in the first quarter of 2008 were not incorporated into future development costs used in the 2007 reserves report, but potentially could be in 2008. The Company's engineers believe that future costs savings are still attainable in the Edmonton Sands program.

On January 11, 2008, the Company announced a preliminary capital expenditure budget of $60 million, which is essentially a cash flow budget based on a wellhead natural gas price of $6.50 per Mcf. The Company expects its spending to range from $60 to $100 million depending on commodity price levels. The Company plans to spend $38 million in the first quarter of the year and then reassess the budget after spring break up depending on the outlook for natural gas prices at that time. If the outlook for natural gas prices remains positive, the Company could prudently spend as much as $100 million in the year by pursuing a larger drilling program in the last six months of the year.

In the first quarter of 2008, the Company drilled 71 gross (56 net) Edmonton Sands wells and three 100% working interest Mannville development wells at a depth of 1,800 metres. This is the largest quarterly drilling program undertaken by the Company and, based on completion results, it appears to be the most successful quarterly program undertaken to date. The Mannville gas wells drilled in the first quarter were successfully completed and tested at 4,000, 600 and 200 Mcfd, respectively.

The large first quarter drilling program was designed to take advantage of expected lower costs on frozen ground conditions. This will enable the Company to tie-in wells for production earlier in the year and at lower costs. The Company is constructing three natural gas plants which, when completed, will reduce operating expenses in the second half of the year. As well, these facilities will improve onstream factors and provide more production capacity for additional drilling. These natural gas plant projects are all in the Greater Sylvan Lake area and include the installation of a refrigeration plant at the existing Willesden Green compressor station and two new natural gas compressor stations at Wilson Creek and Buck Lake. In addition to the plant infrastructure acquired in the September 2007 acquisition and the installation of the three new gas plants, the Company's engineers and field personnel are focused on reducing operating expenses in the field.

As of December 31, 2007, the Company has identified 1,161 gross (585 net) drilling locations of which 85% are net Edmonton Sands locations and 7.5% are net Horseshoe Canyon CBM locations. The Company expects it to take approximately six to eight years to drill these locations. Net of locations drilled, the Company increased its drilling inventory in 2007 by 370 gross (291 net) locations, primarily in the Edmonton Sands area. The Company's Edmonton Sands drilling inventory is calculated based on four wells per section. When the Company elects to down space to six to eight wells per section, there will be a significant increase to its drilling inventory.

The Company has significantly grown its Edmonton Sands land position on a net section basis with the December 31, 2007 land inventory being 303 gross (179 net) sections. As of March 15, 2008, the land inventory increased to 316 gross (190 net) sections.

On October 25, 2007, the Alberta government proposed significant upward revisions to the Crown royalty regime in the province. While the proposed changes are expected to have a negative impact on the oil and gas business as a whole, the impact on shallow gas programs is expected to be less than on other areas of the business. Anderson Energy believes that the proposed changes will have only a small impact on royalties payable at current production levels and prices. At natural gas prices less than $7.50 per Mcf, the proposed royalty changes are in fact slightly beneficial to the Edmonton Sands program. The changes do not negatively impact our long term Edmonton Sands business strategy, as the focus is predominantly on shallow gas lower productivity wells, and approximately 34% of our prospects are on freehold lands. The overall impact on the Company's net asset value is a reduction of 1.7% based on AJM's December 31, 2007 price deck. The Alberta government also announced that it intends to pursue some form of shallow rights reversion. Depending on how and when such reversion is implemented, if at all, the Company believes this could be a positive development for its Edmonton Sands play.

In the balance of 2008, the Company expects to expand its drilling inventory through acquisitions and/or farm-ins in central Alberta. The Company will be reviewing its spending plans when it reviews the outlook for natural gas prices after spring breakup. The Company will also be carefully examining potential property and corporate acquisitions in 2008.

The outlook for natural gas has improved substantially in the last few months. The United States natural gas storage is 9.7% less than the previous year's natural gas in storage and 4.3% higher than the five year average. The improvement in the natural gas storage and higher oil prices has driven the NYMEX natural gas futures market to prices in the $10.00 US/MMbtu range for next winter.

Anderson Energy's share price performance is linked to natural gas prices which have been weak in the last couple of years. With natural gas prices becoming stronger, we expect the share price to do the same. The Company's shares are trading at a significant discount to net asset value and at less than $10.00 per BOE of proved plus probable reserves. Initial 2008 average production guidance is 8,200 to 8,600 BOED, representing a 54% to 61% growth in production volumes over 2007.

The Company will be publishing its annual report at the end of March 2008. In this report, we will provide a more detailed operational overview of the Company's activities. We invite our shareholders to attend the Company's third annual meeting as a public company on May 14, 2008 at the Metropolitan Centre in Calgary at 2:00 pm MDT.

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



Brian H. Dau
President and Chief Executive Officer
March 18, 2008


Management's Discussion and Analysis

For the Years Ended December 31, 2007 and 2006:

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 years ended December 31, 2007 and 2006 and is based on information available as of March 17, 2008.

The following information is based on financial statements prepared by management in accordance with Canadian generally accepted accounting principles ("GAAP"). Production and reserves numbers are stated before deducting Crown or lessor royalties.

Included in the discussion and analysis are references to terms commonly used in the oil and gas industry such as funds from operations, finding, development and acquisition ("FD&A") costs and barrels of oil equivalent. Funds from operations as used in this report represent cash from operating activities before changes in non-cash working capital and asset retirement expenditures. See "Review of Financial Results - Funds from Operations" for details of this calculation. Funds from operations represent both an indicator of the Company's performance and a funding source for on-going operations. FD&A costs measure the cost of reserve additions and are an indicator of the efficiency of capital expended in the period. Production volumes and reserves are commonly expressed on a barrel of oil equivalent ("BOE") basis whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil and natural gas measurement units into one basis for improved analysis of results and comparisons with other industry participants. These terms are not defined by Canadian GAAP and therefore are referred to as non-GAAP measures.

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

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

Review of Financial Results

Sales volumes for the year ended December 31, 2007 averaged 5,328 BOED, which were 30% higher than the previous year, but lower than anticipated due to unusually wet weather conditions in the summer and fall that delayed drilling and tie-in operations. This, combined with declines in natural gas prices, resulted in lower funds from operations than expected. In the fourth quarter, when field conditions permitted the Company to resume operations, 37 wells were tied-in in the last six weeks of the year helping the Company to achieve its exit production target of 8,000 BOED.

Net capital expenditures in the year were $211.1 million. These expenditures included two significant acquisitions in the Greater Sylvan Lake area - the first on June 29, 2007 for $9.2 million and the second on September 1, 2007 for $117.6 million. Reserves increased significantly as a result of the acquisitions, drilling and completion operations and various farm-in transactions. Reserves were added at a FD&A cost (including future development capital) of $19.55 per BOE for proved reserves and $16.71 per BOE for proved and probable reserves.

On April 24, 2007, the Company issued 7,935,000 common shares at a price of $4.35 per share for gross proceeds of $34.5 million ($32.5 million after commission and expenses). On August 31, 2007, the Company issued 25,700,000 common shares at a price of $3.90 per share for gross proceeds of $100.2 million ($94.7 million after commission and expenses) in conjunction with the acquisition completed on September 1, 2007. The Company now has 87.3 million common shares outstanding.

Bank lines were increased to $105 million during the year. Subsequent to year end, the Company arranged for an additional one year supplemental credit facility of $25 million.

Revenue and Production:

Gas sales comprised 84% of Anderson Energy's total oil and gas sales volumes for the year ended December 31, 2007, consistent with the prior year.

Gas sales volumes for the year ended December 31, 2007 increased 30% to an average of 26.9 MMcfd from 20.8 MMcfd last year. The increase reflects the acquisition of oil and gas assets in June and September 2007 and new wells on production as a result of drilling during the year. The Greater Sylvan Lake area remains the Company's largest area of production, with gas sales averaging 17.8 MMcfd during 2007. Gas sales volumes were negatively impacted during the third quarter by third party plant turnarounds and wet field conditions which delayed the tie-in of wells. Drilling and tie-in activity near the end of the year added significant production by the end of the year.

The Company achieved average gas sales of 35.7 MMcfd in the fourth quarter of 2007. This compares to 26.9 MMcfd in the third quarter of 2007 and 21.1 MMcfd in the fourth quarter of 2006. Fourth quarter gas sales reflect the first full quarter of production from the September 2007 acquisition.

Oil sales for the year ended December 31, 2007 averaged 540 bpd compared to 485 bpd for the year ended December 31, 2006. Oil production averaged 602 bpd in the fourth quarter of 2007 compared to 485 bpd in the third quarter of 2007 and 512 bpd in the fourth quarter of 2006. The majority of the Company's oil production is from Central and Eastern Alberta.

Natural gas liquids sales for the year ended December 31, 2007 averaged 297 bpd compared to 163 bpd for the year ended December 31, 2006. Natural gas liquids sales averaged 548 bpd in the fourth quarter of 2007 compared to 358 bpd in the third quarter of 2007 and 180 bpd in the fourth quarter of 2006. Edmonton Sands natural gas production at Sylvan Lake is dry and produces minimal amounts of natural gas liquids. The assets acquired in the September 2007 acquisition are richer in liquids than the Company's Edmonton Sands production.

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
------------------------- -----------------
2007 2006 2007 2006
---- ---- ---- ----

Oil and Natural Gas Revenue
(thousands of dollars)
Natural gas $ 20,001 $ 13,232 $ 62,558 $ 49,322
Natural gas hedging gains - - 1,157 -
Oil 3,993 2,385 12,369 10,240
NGL 3,653 870 6,927 3,463
Royalty and other 128 333 574 787
------------------------ --------------------
Total $ 27,775 $ 16,820 $ 83,585 $ 63,812
------------------------ --------------------
------------------------ --------------------


Three months ended Dec 31 Year ended Dec 31
------------------------- -----------------
2007 2006 2007 2006
---- ---- ---- ----
Production
Natural gas (Mcfd) 35,672 21,075 26,942 20,787
Oil (bpd) 602 512 540 485
NGL (bpd) 548 180 297 163
-------------------------- -----------------
Total (BOED) 7,095 4,205 5,328 4,113
------------------------ -----------------
------------------------ --------------------


Three months ended Dec 31 Year ended Dec 31
------------------------- -----------------
2007 2006 2007 2006
---- ---- ---- ----
Prices
Natural gas ($/Mcf) $ 6.09 $ 6.82 $ 6.48 $ 6.50
Oil ($/bbl) 72.12 50.61 62.71 57.81
NGL ($/bbl) 72.45 52.49 63.88 58.07
Total ($/BOE) (i) 42.55 43.48 42.98 42.50
(i) Includes royalty and other income classified with oil and gas sales.


Anderson Energy's average gas sales price was $6.48 per Mcf for the year ended December 31, 2007 compared to $6.50 per Mcf for the year ended December 31, 2006. For the three months ended December 31, 2007, the gas sales price was $6.09 per Mcf. This compares to $5.00 per Mcf realized in the third quarter of 2007 and $6.82 per Mcf realized in the fourth quarter of 2006. Gas prices decreased significantly over the course of the year due to historically high levels of natural gas storage. The natural gas price in 2007 includes hedging gains of $1.2 million. The 2007 gas price before hedging gains was $6.36 per Mcf.

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

Hedging Contracts:

There were no physical or financial hedging contracts outstanding as at December 31, 2007. In January 2008, as part of its risk management program, the Company entered into fixed price natural gas contracts to manage commodity price risk. The Company has physical contracts to sell 25,000 GJ per day of natural gas for February and March 2008 at an average price of $6.89 per GJ at AECO.

Royalties:

Royalties were 19% of revenue for the year ended December 31, 2007 compared to 21% of revenue for the year ended December 31, 2006. Royalties were 19% of revenue in the fourth quarter of 2007 compared to 19% of revenue in the third quarter and 18% of revenue in the fourth quarter of 2006. Royalty rates decreased from the prior year as a result of lower gas prices and higher gas cost allowance. In 2006, the Company received Alberta Royalty Tax Credits of $500,000. This program has been discontinued in 2007. The Company expects 2008 royalties to increase overall as production increases and the average royalty rate as a percentage of revenue to increase if prices increase in 2008. On October 25, 2007, the Alberta government announced proposed changes to the Crown royalty system. These changes are expected to come into effect on January 1, 2009 and are discussed further under "Business Risks".



Three months ended Dec 31 Year ended Dec 31
------------------------- -----------------
2007 2006 2007 2006
---- ---- ---- ----

Royalties (%) 19% 18% 19% 21%
Royalties ($/BOE) $ 7.89 $ 7.68 $ 8.10 $ 8.86


Operating Expenses:

Operating expenses were $11.70 per BOE for the year ended December 31, 2007 compared to $9.95 per BOE for the year ended December 31, 2006. Operating expenses were $11.71 in the fourth quarter of 2007 compared to $11.83 in the third quarter and $10.30 in the fourth quarter of 2006. In addition to overall increases in costs, additional costs relating to a series of workovers, pump changes and compressor repairs as well as third party 2005 and 2006 gas processing adjustments increased operating costs on a BOE basis in 2007. Various shut-ins, including a shut-in at Chinchaga in the first quarter and a shut-in at Minnehik Buck Lake in the third quarter, also increased operating costs on a BOE basis. Operating costs are expected to increase overall as production increases but to decrease on a BOE basis in 2008 as the Company becomes less dependent on third party processing. Various plant interests were acquired as part of the September 2007 acquisition and three large plant construction projects at Willesden Green, Wilson Creek and Buck Lake are expected to be completed in the second half of the year.

Operating Netback:



Three months ended Dec 31 Year ended Dec 31
------------------------- -----------------
2007 2006 2007 2006
---- ---- ---- ----
(thousands of dollars)

Revenue $ 27,775 $ 16,820 $ 83,585 $ 63,812
Royalties (5,152) (2,971) (15,758) (13,305)
Operating expenses (7,645) (3,983) (22,743) (14,934)
------------------------- ----------------------
$ 14,978 $ 9,866 $ 45,084 $ 35,573
------------------------- ----------------------
------------------------- ----------------------

Sales (MBOE) 652.8 386.9 1,944.7 1,501.3


Per BOE
Revenue $ 42.55 $ 43.48 $ 42.98 $ 42.50
Royalties (7.89) (7.68) (8.10) (8.86)
Operating expenses (11.71) (10.30) (11.70) (9.95)
------------------------- ----------------------
$ 22.95 $ 25.50 $ 23.18 $ 23.69
------------------------- ----------------------
------------------------- ----------------------


General and Administrative Expenses:

General and administrative expenses were $6.3 million or $3.25 per BOE for the year ended December 31, 2007 compared to $4.9 million or $3.24 per BOE for the year ended December 31, 2006. General and administrative expenses were $2.13 per BOE in the fourth quarter of 2007 compared to $3.23 per BOE in the third quarter and $4.10 per BOE in the fourth quarter of 2006. General and administrative expenses increased overall in 2007 as a result of increased salaries, rent and reserve report costs and lower capital overhead recoveries but decreased on a BOE basis as these costs were spread over higher levels of production.



Three months ended Dec 31 Year ended Dec 31
------------------------- -----------------
(thousands of dollars) 2007 2006 2007 2006
---- ---- ---- ----
General and administrative
(gross) $ 2,784 $ 2,747 $ 10,799 $ 9,758
Overhead recovery (614) (498) (1,669) (2,021)
Capitalized (780) (663) (2,809) (2,873)
------------------------ -----------------
General and administrative
(net) $ 1,390 $ 1,586 $ 6,321 $ 4,864
-------------------------- --------------------
-------------------------- --------------------
General and administrative
($/BOE) $ 2.13 $ 4.10 $ 3.25 $ 3.24
% Capitalized 28% 24% 26% 29%


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

Stock Based Compensation:

The Company accounts for stock-based compensation plans using the fair value method of accounting. Stock-based compensation expense was $1.2 million in 2007 ($0.6 million net of amounts capitalized) versus $0.7 million ($0.4 million net of amounts capitalized) in 2006. The increase is a result of additional stock options being granted to new and existing staff members.

Interest Expense:

Interest expense was $2.6 million for the year ended December 31, 2007 compared to $1.6 million in 2006. In the fourth quarter of 2007, interest expense was $1.0 million compared to $0.6 million in the third quarter of 2007 and $0.3 million in the fourth quarter of 2006. Interest expense was higher in 2007 due to higher debt levels and somewhat higher interest rates. The average effective interest rate on outstanding bank loans was 5.9% in 2007 compared to 5.4% in 2006. Interest expense is expected to increase in 2008 as a result of higher debt levels associated with the Company's front-end loaded capital program.

Depletion and Depreciation:

Depletion and depreciation was $20.96 per BOE for the year ended December 31, 2007 compared to $24.50 per BOE in 2006. Depletion and depreciation was $20.76 per BOE in the fourth quarter of 2007 compared to $20.75 per BOE in the third quarter and $21.85 per BOE in the fourth quarter of 2006. Depletion and depreciation expense is calculated based on proved reserves only. The recent reserve evaluation completed by AJM Petroleum Consultants ("AJM") increased the ratio of proved to proved plus probable reserves to 72% from 65% in 2006. The higher allocation to proved reserves has resulted in a significant decrease in depletion and depreciation expense on a BOE basis.

Asset Retirement Obligation:

As a result of new drilling, the Company recorded $0.4 million in asset retirement obligations in the fourth quarter of 2007 and $1.6 million for the year ended December 31, 2007. Asset retirement obligations associated with the September 2007 acquisition were $5.9 million. Asset retirement obligations associated with the June 2007 acquisition were $1.5 million. Accretion expense was $1.4 million for 2007 compared with $0.9 million for 2006 and was included in depletion and depreciation expense. Accretion expense increased year over year due to new drills and acquisitions.

Income Taxes:

Anderson Energy is not currently taxable. The Company does not anticipate paying current income tax in 2008. The estimated tax pool balances at December 31, 2007 are summarized below. Tax pool classifications are estimates as some new wells have not yet had their status as exploratory or development confirmed. The balances below have been reduced for the effect of income recorded in 2007 that will not be taxed until 2008.



Canadian Exploration Expenses (CEE) $ 55 million
Canadian Development Expenses (CDE) 61 million
Undepreciated Capital Cost (UCC) 93 million
Canadian Oil and Gas Property Expenses (COGPE) 25 million
Non-Capital Losses and Other 41 million
-------------
Total $ 275 million
-------------
-------------


The effect of enacted federal income tax rate reductions resulted in a $6.7 million reduction in the future tax provision in the fourth quarter.

The assets acquired in the September 2007 acquisition were acquired through the purchase of a subsidiary of the vendor. The tax pools associated with the acquisition were limited to $23.4 million of UCC and $0.4 million of CEE. As a result of the difference between the price paid for the assets and the tax pools acquired, a future income tax liability of $30.6 million was recorded as part of the purchase equation.

A $15.0 million flow-through financing was completed on September 25, 2006. The Company committed to use 20% of the gross proceeds to incur CEE and 80% to incur 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 of 2006, 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 used the look back rule for approximately $1.6 million of the CEE commitment and this amount was spent in 2007.

Funds from Operations:

Funds from operations increased by 25% to $36.4 million compared to $29.2 million in 2006. On a per share basis, funds from operations were $0.54 per share in 2007 compared to $0.58 per share in 2006. For the three months ended December 31, 2007, funds from operations were $12.6 million or $0.14 per share, an increase of 101% over the previous quarter of $6.3 million or $0.09 per share. The increase in the fourth quarter was due to improved natural gas prices and higher production associated with the September 2007 acquisition. It is expected that as the properties associated with the acquisition are developed, the acquisition will be accretive to funds from operations on a per share basis.



Three months ended Year ended
Dec 31 Dec 31
(thousands of dollars) 2007 2006 2007 2006
------------------ -----------------
Cash from operating activities $ 11,110 $ 8,651 $ 34,259 $ 32,531
Changes in non-cash working capital 1,404 (697) 1,413 (3,735)
Asset retirement obligations 50 42 742 405
------------------ -----------------
Funds from operations $ 12,564 $ 7,996 $ 36,414 $ 29,201
------------------ -----------------
------------------ -----------------


Cash from operating activities also increased year over year but to a lesser degree than funds from operations due to changes in working capital. These changes were largely the result of increases in accrued revenue due to the September 2007 acquisition.

Earnings:

The Company reported earnings of $4.9 million in the fourth quarter and earnings of $2.2 million for the year ended December 31, 2007 compared to earnings of $0.8 million for the fourth quarter of 2006 and a $3.5 million loss for the year ended December 31, 2006. Earnings in 2007 were affected by the federal income tax rate reductions enacted in the fourth quarter.

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



Funds from Operations Earnings
Sensitivities: Millions Per Share Millions Per Share
-------- --------- -------- ---------
$0.50/Mcf in price of natural gas $ 6.5 $ 0.07 $ 4.6 $ 0.05
US $5.00/bbl in the WTI crude
price $ 1.7 $ 0.02 $ 1.2 $ 0.01
US $0.01 in the U.S./Cdn exchange
rate $ 1.1 $ 0.01 $ 0.8 $ 0.01
1% in short-term interest rate $ 1.1 $ 0.01 $ 0.8 $ 0.01


Capital Expenditures

The Company spent $30.3 million in capital expenditures in the fourth quarter and $211.1 million for the year ended December 31, 2007. The breakdown of expenditures is shown below:



Three months
ended Dec 31 Year Ended Dec 31
------------ -----------------
(thousands of dollars) 2007 2007 2006
---- ---- ----
Land, geological & geophysical costs $ 35 $ 2,081 $ 5,100
Acquisitions, net of dispositions (i) 120 126,564 (2,868)
Drilling, completion and recompletion 17,452 42,128 50,830
Facilities and well equipment 11,899 35,485 24,592
Capitalized G&A 780 2,809 2,873
------------ ---------- ---------
Total FD&A expenditures 30,286 209,067 80,527
Compressor and other equipment
inventory (93) 1,879 -
Office equipment and furniture 107 187 85
------------ ---------- ---------
Total capital expenditures 30,300 211,133 80,612
Non-cash asset retirement obligations
and
capitalized stock based compensation 653 3,632 3,421
------------ ---------- ---------
Total cash and non-cash capital
additions $ 30,953 $ 214,765 $ 84,033
------------ ---------- ---------
------------ ---------- ---------
(i) Acquisitions in 2006 include $6.8 million in property purchases for
common shares.


In addition, a gross-up of capital costs and an associated future income tax liability of $15.7 million were recorded to reflect the minimal tax basis associated with the September 2007 acquisition and the lack of tax basis associated with capitalized stock based compensation costs.


Drilling statistics are shown below:



Three months ended Dec 31 Year ended Dec 31
------------------------- -----------------
2007 2006 2007 2006
---- ---- ---- ----
Gross Net Gross Net Gross Net Gross Net
----- --- ----- --- ----- --- ----- ---

Gas 37 29.8 49 34.2 106 75.6 128 70.1
Oil - - - - 5 2.2 6 4.0
Dry 3 2.2 5 4.4 11 6.9 12 9.7
------------------------------- ----------------------------
Total 40 32.0 54 38.6 122 84.7 146 83.8
------------------------------- ----------------------------
------------------------------- ----------------------------

Success
rate (%) 93% 93% 91% 89% 91% 92% 92% 88%


The Company drilled 86 gross (74.6 net) Edmonton Sands wells in 2007 of which 33 gross (30 net) wells were drilled in the fourth quarter.

Ceiling Test/Goodwill Impairment

At December 31, 2007, the ceiling test resulted in the undiscounted cash flows from proved reserves being in excess of the carrying value of the underlying petroleum and natural gas assets and as such no ceiling test write-down was required. Prices used for the 2007 ceiling test are presented in note 4 of the consolidated financial statements.

Anderson Energy recorded goodwill as a result of acquisitions made in 2005 and 2007. Goodwill represents the excess of the purchase price of the acquired businesses over the fair value of net assets acquired and is assessed at least annually in the fourth quarter for impairment. The decline in the Company's share price in the fourth quarter of 2007 is one indicator of possible impairment. However, this decline was felt to be more reflective of poor market conditions throughout the sector than the fair value of the Company's business. At December 31, 2007, the Company's net asset value was $5.17 per share, almost double the share price and well in excess of the book value of equity. No impairment of goodwill was determined.

Reserves and FD&A Costs

Finding, development and acquisition costs, including future development capital, were $19.55 per BOE on a proved basis and $16.71 per BOE on a proved plus probable basis. This compares to $13.30 per BOE on a proved basis and $13.36 per BOE on a proved plus probable basis in 2006. FD&A costs increased over 2006 largely as a result of acquisitions, which comprised 60% of total capital expenditures in the year, and some negative revisions to reserves.

The Company's reserves were evaluated by AJM in accordance with National Instrument 51-101 ("NI 51-101") as of December 31, 2007. The tables in this section are an excerpt from what will be contained in the Company's Annual Information Form ("AIF") as the Company's NI 51-101 annual required filings.





SUMMARY OF GROSS OIL AND GAS RESERVES
AS AT DECEMBER 31, 2007

Natural Natural Gas
Gas Oil Liquids Total BOE
------- --- ----------- ----------
(Bcf) (Mbbls) (Mbbls) (MBOE)

Proved developed producing 62.0 667 1,012 12,001
Proved developed
non-producing 4.1 11 71 768
Proved undeveloped 93.2 175 414 16,124
----------------------------------------
Total proved 159.3 853 1,497 28,893
Probable 59.8 405 617 10,995
----------------------------------------
Total proved plus probable 219.1 1,258 2,114 39,888
----------------------------------------
----------------------------------------
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, 2007 PRICE FORECAST, ESCALATED PRICES)

(thousands of dollars) 0% 5% 10% 15%
--------------------------------------------
Proved developed producing $ 324,332 $ 262,599 $ 225,518 $ 199,136
Proved developed non-producing 21,681 15,141 11,440 9,072
Proved undeveloped 300,081 211,532 150,276 107,863
--------------------------------------------
Total proved 646,094 489,272 387,234 316,071
Probable 306,723 204,608 145,221 107,815
--------------------------------------------
Total proved plus probable $ 952,817 $ 693,880 $ 532,455 $ 423,886
--------------------------------------------
--------------------------------------------
The estimated net present value of future net revenues presented in the
table above does not necessarily represent the fair value of the Company's
reserves.



SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
AS AT DECEMBER 31, 2007
FORECAST PRICES AND COSTS


Oil Natural Gas Edmonton Liquids Prices
--- ----------- -----------------------
WTI Edmonton AECO Butane Pentanes
Cushing City Gate Gas Price Propane Plus
Year ($US/bbl) ($Cdn/bbl) ($Cdn/Mcf) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl)
---- --------- ---------- ---------- ---------- ---------- ----------
2008 85.0 85.65 6.90 55.65 68.50 89.95
2009 81.60 84.75 7.75 55.10 67.80 89.00
2010 81.15 87.05 8.10 56.60 69.65 91.40
2011 79.60 87.25 8.50 56.70 69.80 91.60
2012 77.95 85.40 8.65 55.50 68.30 89.65
2013 77.30 84.60 9.10 55.00 67.70 88.85
there-
after
2%

Inflation Exchange
Rate Rate
Year % (US$/Cdn$)
---- --------- ---------
2008 - 0.98
2009 2.0 0.95
2010 2.0 0.92
2011 2.0 0.90
2012 2.0 0.90
2013 2.0 0.90
there-
after
2%


Total future development costs included in the reserves evaluation were $177.8 million for total proved reserves and $235.4 million for total proved plus probable reserves. Further details related to future development costs, including assumptions regarding the timing of the expenditures, will be included in the Company's AIF for the 2007 fiscal year. Future development costs are associated with the reserves as disclosed in the AJM report and do not necessarily represent the Company's current exploration and development budget.



CONTINUITY OF GROSS RESERVES

Natural Gas Oil & Natural Gas Liquids
----------- -------------------------
(Bcf) (Mbbls)
----- -------
Proved Probable Total Proved Probable Total
------ -------- ----- ------ -------- -----
Opening Balance,
December 31, 2006 92.1 49.6 141.7 888 583 1,471
Drilling Activity 41.3 (1.3) 40.0 330 87 417
Net Acquisitions 43.4 19.4 62.8 1,390 512 1,902
Revisions (7.7) (7.9) (15.6) 48 (160) (112)
Production (9.8) - (9.8) (306) - (306)
-------------------------------------------------------
Closing Balance,
December 31, 2007 159.3 59.8 219.1 2,350 1,022 3,372
-------------------------------------------------------
-------------------------------------------------------
Note: Closing balance for natural gas includes 7.1 Bcf of proved and
2.7 Bcf of probable Coal Bed Methane reserves.



FINDING, DEVELOPMENT & ACQUISITION COSTS

Finding, Change in Finding,
Development Future Net Development
& Acquisition Development Additions & Acquisition
Expenditures Costs Total Costs (i) Costs
(thousands) (thousands) (thousands) (MBOE) ($/BOE)
------------------------------------------------------------------
2007
Proved $ 209,067 $ 76,274 $ 285,341 14,596 $ 19.55
2007
Proved
plus
probable 209,067 70,618 279,685 16,735 16.71
2006
Proved 80,527 27,980 108,507 8,159 13.30(ii)
2006
Proved
plus
probable 80,527 29,830 110,357 8,263 13.36(ii)
3 year
Average
proved 439,213 172,187 611,400 30,785 19.86
3 year
Average
proved 439,213 216,178 655,391 39,090 16.77
plus
probable
(i) Net Additions are defined as gross reserve additions minus gross
reserve revisions.
(ii) Restated from prior years for reclassifications of non-cash costs.


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. BOEs 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.

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, 2007, there were 87.3 million common shares outstanding and 6.3 million stock options outstanding. During 2007, 33.6 million shares were issued pursuant to prospectuses and 18,000 shares were issued under the employee stock option plan. The annualized trading turnover ratio was 50%. As of March 17, 2008, there were 87.3 million shares outstanding and 6.3 million stock options outstanding. The Company's market capitalization at March 17, 2008 was $275.9 million.



Share Price on TSX 2007 2006
---- ----

High $ 5.40 $ 8.00
Low $ 2.53 $ 3.53
Close $ 2.88 $ 3.88
Volume 43,601,931 21,340,486

Shares outstanding at December 31 87,294,401 53,641,401
Market capitalization at December 31 $ 251,407,875 $ 208,128,636


Related Party Transactions

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

Liquidity and Capital Resources

At December 31, 2007, the Company had outstanding bank loans of $68.0 million and a working capital deficiency of $28.9 million. The large working capital deficiency is due to accruals associated with the ramp up in the capital program in the last six weeks of the year.

The Company expects to spend $60 million in capital in 2008 which is essentially a "cash flow" budget. The Company expects that its capital spending in 2008 could range from $60 million to $100 million depending on commodity prices. The current budget assumes an average wellhead natural gas price of $6.50 per Mcf for the year. The Company plans to spend $38 million in the first quarter of 2008 and then reassess the budget after spring break up given the outlook for natural gas prices at that time.

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 facilities from $55 million at December 31, 2006 to $105 million at December 31, 2007. With the heavy spending forecast in the first quarter of 2008, the Company further increased its facilities through a $25 million supplemental credit facility early in 2008. The supplemental facility decreases to $10 million on September 30, 2008 and must be repaid in full by December 31, 2008. Anderson Energy will prudently use its bank loan facilities to finance its operations as required. Anderson Energy anticipates that it will make use of equity financing for any significant expansion in its capital program.

Contractual Obligations

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

- Loan agreements - These reserves-based credit facilities have a revolving period ending July 15, 2008 extendible at the option of the lender, followed by a term period with three equal quarterly principle repayments commencing 180 days from the term date. The Company will be requesting an extension of the revolving period to July 15, 2009 following the filing of its 2007 audited consolidated financial statements.

- Lease for office space - This lease expires on November 30, 2012. Future minimum lease payments are expected to be $1.8 million per year in 2008 through 2011, and $1.6 million in 2012.

- Firm service transportation commitments - The Company has entered into firm service transportation agreements for approximately 25 million cubic feet per day of gas sales for various terms expiring between 2008 and 2015.

- Flow through share commitment - On February 28, 2007, the Company renounced $15 million of qualifying expenditures under flow-through share arrangements entered into in 2006. As of December 31, 2007, the Company has incurred all of the qualifying expenditures under the commitment.

These obligations are described further in other parts of this discussion and analysis and in the notes to the consolidated financial statements.

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 NI 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 reserves evaluator has prepared the Company's oil and gas reserves 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 reserves 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. The Company estimates its future income tax rate in calculating its future income tax liability. Various assumptions are made in assessing when temporary differences will reverse and this will impact the rate used.

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, forfeitures, 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 fair value of the Company falls below the book value of its equity.

Changes in Accounting Policies

Effective January 1, 2007, the Company adopted the Canadian Institute of Chartered Accountants Section 3855 "Financial Instruments - Recognition and Measurement," Section 3865 "Hedges", Section 1530 "Comprehensive Income" and Section 3251 "Equity". The adoption of the new standards did not have a material effect on the consolidated financial statements. This change is described in more detail in notes 2 and 8 of the consolidated financial statements.

Effective January 1, 2008, the Company will be required to adopt three new accounting standards: Section 1535 "Capital Disclosures", Section 3862 "Financial Instruments - Disclosures" and Section 3863 "Financial Instruments - Presentation". Section 1535 requires disclosure of an entity's objectives, policies and processes for managing capital, including: quantitative data about what the entity considers capital, whether the entity has complied with any capital requirements and the consequences of non-compliance if the entity has not complied. Sections 3862 and 3863 specify standards of presentation and enhanced disclosures on financial instruments. Although the Company is currently assessing the impact of these standards on its financial statements, it is not anticipated that the adoption of these new standards will impact the amounts reported in the Company's financial statements as they primarily relate to disclosure.

International Financial Reporting Standards

The Canadian Accounting Standards Board has announced its intention to adopt International Financial Reporting Standards ("IFRS") effective January 1, 2011. One of the most significant impacts of the new standards is likely to be that there is no comparable IFRS standard for full cost companies, nor is there likely to be one by the time the new standards come into effect. Experience from overseas countries who have already adopted IFRS indicates a decline in oil and gas earnings and more volatility in earnings.

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

If these new standards are formally adopted on January 1, 2011, it will require creating a January 1, 2010 opening balance sheet and restating 2010 results for comparative purposes as retroactive application with restatement will be required.

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

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, 2007 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, 2007 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, weather and various operational risks. Commodity prices are influenced by local and worldwide supply and demand, the U.S. dollar exchange rate, transportation costs, political stability and seasonal and weather related changes to demand. The industry is subject to extensive governmental regulation with respect to the environment. Operational risks include well performance, uncertainties inherent in estimating reserves, timing of/ability to obtain drilling licences and other regulatory approvals, ability to obtain equipment, expiration of licences and leases, competition from other producers, sufficiency of insurance, ability to manage growth, reliance on key personnel, third party credit risk and appropriateness of accounting estimates. These risks are described in more detail in the Company's AIF filed with Canadian securities regulatory authorities on SEDAR.

Anderson Energy manages these risks by employing competent professional staff, following sound operating practices and using capital prudently. The Company generates its exploration prospects internally and performs extensive geological, geophysical, engineering, and environmental analysis before committing to the drilling of new prospects. Anderson Energy seeks out and employs new technologies where possible. With the Company's extensive drilling inventory and advance planning, the Company can manage the slower pace of regulatory approvals and the requirements for extensive landowner consultation.

The Company has a formal emergency response plan which details the procedures employees and contractors will follow in the event of an operational emergency. The emergency response plan is designed to respond to emergencies in an organized and timely manner so that the safety of employees, contractors, residents in the vicinity of field operations, the general public and the environment are protected. A corporate safety program covers hazard identification and control on the jobsite, establishes Company policies, rules and work procedures and outlines training requirements for employees and contract personnel.

The Company currently deals with a small number of buyers and sales contracts, and ensures those buyers are an appropriate credit risk. The Company continuously evaluates the merits of entering into fixed price or financial hedge contracts for price management.

Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder to set legally binding targets to reduce nation-wide emissions of carbon dioxide, methane, nitrous oxide and other "greenhouse gases". In response to the Kyoto Protocol, the Canadian federal government introduced the Regulatory Framework for Air Emissions (the "Regulatory Framework") for regulating air pollution and industrial greenhouse gas ("GHG") emissions by establishing mandatory emissions reduction requirements on a sector basis. Sector-specific regulations are expected to come into force in 2010 and targets would be based on percentages rather than absolute reductions. The Regulatory Framework also proposes a credit emissions trading system. Additionally, regulation can take place at the provincial and municipal level. For example, Alberta introduced the Climate Change and Emissions Management Act, which provides a framework for managing GHG emissions by reducing specific gas emissions relative to gross domestic product to an amount that is equal to or less than 50% of 1990 levels by December 31, 2020 and which imposes duties to report. The accompanying regulation, the Specified Gas Emitters Regulation, effective July 1, 2007, requires mandatory emissions reductions through the use of emissions intensity targets. The Canadian federal government proposes to enter into equivalency agreements with provinces that establish a regulatory regime to ensure consistency with the federal plan, but the success of any such plan is doubtful in the current political climate, leaving multiple overlapping levels of regulation.

Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict the impact of the requirements on Anderson Energy and its operations and financial condition.

On February 16, 2007, the Alberta government announced that a review of the province's royalty and tax regime (including income tax and freehold mineral taxes) pertaining to oil and gas resources, including oil sands, conventional oil and gas, and coal bed methane, would be conducted by a panel of experts with the assistance of individual Albertans and key stakeholders. The review panel published a final report on September 18, 2007. On October 25, 2007, the Alberta government announced their response to the review panel's report. The proposed changes to the Alberta Crown royalty system are expected to come into effect on January 1, 2009. The net impact on the Company will be higher royalties paid on natural gas liquids and crude oil. With 2007 natural gas prices, the Company would expect to pay lower Crown royalties on gas, as the Company is a low productivity per well producer. At natural gas prices in excess of $7.50/Mcf, the Company would expect to pay higher Crown royalties on gas. Approximately 50% of the Company's royalties are paid to the Alberta Crown and as such are affected by the changes.

Business Prospects

The Company has an excellent drilling inventory with over six to eight years of development drilling locations in its core resource plays, the Sylvan Lake Edmonton Sands and Horseshoe Canyon Coal Bed Methane.

During periods of price weakness, our business strategy is to grow our assets and reduce our costs. The Company continues to work on farm-in transactions to grow its Edmonton Sands land and drilling inventory. Anderson Energy currently plans to drill 112 gross (72 net) wells in 2008, with the Edmonton Sands project representing 85% of the net drilling program. The 2008 capital budget is heavily weighted to the first quarter of the year to take advantage of the expected lower costs on frozen ground conditions, to enable the Company to tie-in wells for production earlier in the year and to give the Company the flexibility to increase the budget if prices and markets improve later in the year. The Company also has three natural gas plant projects which, when completed, will help to reduce operating expenses in the second half of the year. In addition, the Company continuously works with its suppliers and service companies to bring the cost of services down. When prices turn around, we will be a stronger company with increased production and more reserves, a larger drilling inventory and a lower cost structure.

The Company's 2008 average production guidance is 8,200 to 8,600 BOED of production, a 54% to 61% increase over 2007 production. Risks associated with this guidance include gas plant capacity, regulatory issues, weather problems and access to industry services.

Quarterly Information

The following table provides financial and operating results for the last eight quarters. The $117.6 million acquisition completed in September, 2007 had a significant impact on capital spent in the third quarter of 2007. The impact of the acquisition on production and funds from operations was not really realized until the fourth quarter of 2007. Natural gas prices were very depressed in the third quarter of 2007, which had a significant impact on funds from operations and earnings in that quarter.



SELECTED QUARTERLY INFORMATION
($ amounts in thousands, except per share amounts and prices)

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

Oil and gas revenue before
royalties $ 27,775 $ 17,261 $ 18,440 $ 20,109
Funds from operations $ 12,564 $ 6,255 $ 8,972 $ 8,623
Funds from operations per share
Basic $ 0.14 $ 0.09 $ 0.15 $ 0.16
Diluted $ 0.14 $ 0.09 $ 0.15 $ 0.16
Earnings (loss) $ 4,867 $ (3,018) $ 368 $ (33)
Earning (loss) per share
Basic $ 0.06 $ (0.04) $ 0.01 $ -
Diluted $ 0.06 $ (0.04) $ 0.01 $ -
Capital expenditures, including
acquisitions net of dispositions $ 30,300 $ 135,966 $ 17,586 $ 27,281
Daily sales
Natural gas (Mcfd) 35,672 26,860 22,928 22,162
Liquids (bpd) 1,150 843 602 750
BOE (bpd) 7,095 5,320 4,423 4,444
Average prices
Natural gas ($/Mcf) $ 6.09 $ 5.00 $ 7.25 $ 8.14
Liquids ($/bbl) $ 72.28 $ 63.31 $ 58.18 $ 52.59
BOE ($/BOE) $ 42.55 $ 35.27 $ 45.81 $ 50.28


Q4 2006 Q3 2006 Q2 2006 Q1 2006
------- ------- ------- --------
Oil and gas revenue before
royalties $ 16,820 $ 14,651 $ 15,452 $ 16,889
Funds from operations $ 7,996 $ 5,873 $ 6,728 $ 8,604
Funds 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, including
acquisitions net of dispositions $ 20,662 $ 10,948 $ 15,994 $ 33,008
Daily sales
Natural gas (Mcfd) 21,075 19,621 21,664 20,799
Liquids (bpd) 692 736 549 614
BOE (bpd) 4,205 4,006 4,160 4,081
Average prices
Natural gas ($/Mcf) $ 6.82 $ 5.71 $ 6.05 $ 7.40
Liquids ($/bbl) $ 51.09 $ 62.14 $ 68.19 $ 51.15
BOE ($/BOE) $ 43.48 $ 39.75 $ 40.82 $ 45.98



SELECTED ANNUAL INFORMATION
Years ended December 31 2007 2006 2005
---- ---- ----
(in thousands, except per share amounts)

Total oil and gas revenues $ 83,585 $ 63,812 $ 46,953
Total oil and gas revenues, net of royalties $ 67,827 $ 50,507 $ 36,780
Earnings (loss) $ 2,184 $ (3,534) $ 731
Earnings (loss) per share (basic) $ 0.03 $ (0.07) $ 0.02
Earnings (loss) per share (diluted) $ 0.03 $ (0.07) $ 0.02
Total assets $ 531,324 $ 317,364 $ 269,412
Total long-term debt $ 67,981 $ 27,627 $ 11,368


Advisory

Certain information regarding Anderson Energy Ltd. in this news release including, without limitation, management's assessment of future plans and operations, number of locations in drilling inventory and wells to be drilled, timing of drilling and tie-in of wells and the costs thereof, productive capacity of the wells, timing of construction of facilities, expected production rates, dates of commencement of production, capital expenditures and timing thereof, value of undeveloped land, extent of reserve additions, ability to attain cost savings, drilling program success, impact of changes to the royalty regime applicable to the Company, commodity price outlook and future share performance, may constitute forward-looking statements under applicable securities laws and necessarily involve risks and assumptions made by management of the Company including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, capital expenditure costs, including drilling, completion and facilities costs, unexpected decline rates in wells, wells not performing as expected, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect Anderson Energy's operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), at Anderson Energy's website (www.andersonenergy.ca). Furthermore, the forward-looking statements contained in this news release are made as at the date of this news release and Anderson Energy does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

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



ANDERSON ENERGY LTD.
Consolidated Balance Sheets
December 31, 2007 and 2006

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

(stated in thousands of dollars) 2007 2006
------------------------------------------------------------

Assets

Current assets:
Cash $ 2 $ 11
Accounts receivable and accruals 31,540 28,885
Prepaid expenses and deposits 2,522 1,968
------------------------------------------------------------
34,064 30,864

Property, plant and equipment (note 4) 461,896 272,180

Goodwill (note 3) 35,364 14,320

------------------------------------------------------------
$ 531,324 $ 317,364
------------------------------------------------------------
------------------------------------------------------------

Liabilities and Shareholders' Equity

Current liabilities:
Accounts payable and accruals $ 62,915 $ 51,890

Bank loans (note 5) 67,981 27,627

Asset retirement obligations (note 6) 24,526 14,905

Future income taxes (note 7) 41,450 17,012
------------------------------------------------------------
196,872 111,434
Shareholders' equity:
Share capital (note 8) 334,147 208,994
Contributed surplus (note 8) 2,005 820
Deficit (1,700) (3,884)
------------------------------------------------------------
334,452 205,930

Commitments (note 12)

------------------------------------------------------------
$ 531,324 $ 317,364
------------------------------------------------------------
------------------------------------------------------------

See accompanying notes to the consolidated financial statements.



ANDERSON ENERGY LTD.
Consolidated Statements of Operations, Comprehensive
Income (Loss) and Deficit
Years ended December 31, 2007 and 2006

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

(stated in thousands of dollars,
except per share amounts) 2007 2006
------------------------------------------------------------

Revenues
Oil and gas sales $ 83,585 $ 63,812
Royalties (15,758) (13,305)
Interest income 297 99
------------------------------------------------------------
68,124 50,606
Expenses
Operating 22,743 14,934
General and administrative 6,321 4,864
Stock-based compensation 613 362
Interest and other financing
charges 2,646 1,607
Depletion, depreciation and
accretion 42,137 37,723
------------------------------------------------------------
74,460 59,490

------------------------------------------------------------
Loss before taxes (6,336) (8,884)

Future income tax reduction (note 7) (8,520) (5,350)
------------------------------------------------------------
Earnings (loss) for the year 2,184 (3,534)

Reclassification of accumulated
other comprehensive income to
earnings (notes 2 and 8) (1,465) -

------------------------------------------------------------
Comprehensive income (loss) $ 719 $ (3,534)
------------------------------------------------------------
------------------------------------------------------------


Deficit, beginning of year $ (3,884) $ (350)
Earnings (loss) for the year 2,184 (3,534)

------------------------------------------------------------
Deficit, end of year $ (1,700) $ (3,884)
------------------------------------------------------------
------------------------------------------------------------


Earnings (loss) per share (note 8)
Basic $ 0.03 $ (0.07)
Diluted $ 0.03 $ (0.07)

See accompanying notes to the consolidated financial statements.



ANDERSON ENERGY LTD.
Consolidated Statements of Cash Flows
Years ended December 31, 2007 and 2006

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

(stated in thousands of dollars) 2007 2006
----------------------------------------------------------------------------

Cash provided by (used in):

Operations
Earnings (loss) for the year $ 2,184 $ (3,534)
Items not involving cash
Depletion, depreciation and accretion 42,137 37,723
Future income tax reduction (8,520) (5,350)
Stock-based compensation 613 362
Asset retirement expenditures (742) (405)
Changes in non-cash working capital
Accounts receivable and accruals (5,894) 1,708
Prepaid expenses and deposits (371) (576)
Accounts payable and accruals 4,852 2,787
Capital taxes payable - (184)
----------------------------------------------------------------------------
34,259 32,531

Financing
Increase in bank loans 40,354 16,259
Issue of common shares, net of issue costs 127,282 20,993
----------------------------------------------------------------------------
167,636 37,252

Investments
Additions to property, plant and equipment (93,979) (86,249)
Acquisition of 3210700 Nova Scotia Company (note 3) (117,634) -
Payment of liabilities assumed on
acquisition (note 3) (324) -
Proceeds on disposition of properties 804 12,404
Changes in non-cash working capital
Accounts receivable and accruals 3,239 710
Prepaid expenses and deposits (183) 170
Accounts payable and accruals 6,173 2,683
----------------------------------------------------------------------------
(201,904) (70,282)

----------------------------------------------------------------------------
Decrease in cash (9) (499)

Cash, beginning of year 11 510
----------------------------------------------------------------------------

Cash, end of year $ 2 $ 11
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See note 9 for additional cash information.

See accompanying notes to the consolidated financial statements.


ANDERSON ENERGY LTD.

Notes to the Consolidated Financial Statements

Years ended December 31, 2007 and 2006

(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.

1. Significant accounting policies

(a) Basis of presentation

These consolidated financial statements include the accounts of Anderson Energy Ltd. and its wholly owned subsidiaries and a partnership and have been prepared by management in accordance with accounting principles generally accepted in Canada. All inter-entity transactions and balances have been eliminated. 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. Specifically, the amounts recorded for depletion and depreciation of oil and gas properties and the accretion of asset retirement obligations are based on estimates. The ceiling test is based on estimates of reserves, production rates, oil and gas prices, future costs and other relevant assumptions. The amounts for stock-based compensation are based on estimates of risk-free rates, expected lives, forfeitures and volatility. Future income taxes are based on estimates as to the timing of the reversal of temporary differences and tax rates currently substantively enacted. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be significant.

(b) Cash

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

(c) Property, plant and equipment

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, plant and production equipment costs, asset retirement costs and that portion of general and administrative expenses directly attributable to exploration and development activities. 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 properties may have occurred, and at least annually in the fourth quarter. 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 proved reserves plus the cost of unproved properties, 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 properties, 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.

(d) 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, equipment is put in place or in the event of an acquisition. The fair value is discounted using the Company's credit adjusted, risk free rate with the associated asset retirement costs capitalized as part of the carrying amount of property, plant and equipment 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 increased at the end of each period to reflect the passage of time resulting in an accretion charge to earnings. The obligations are also adjusted for changes in the estimated future cash flows underlying the obligation. Actual costs incurred upon settlement of the retirement obligation are charged against the obligation to the extent of the liability recorded.

(e) 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 in the fourth quarter 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, deemed to be the reporting unit, 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.

(f) 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 that are substantively enacted and expected to apply in the periods when the temporary differences are expected to reverse. The effect of a change in rates on future income tax assets and liabilities is recognized in the period that the change occurs.

(g) 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.

(h) 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.

(i) Revenue recognition

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

(j) Financial instruments

A financial instrument is any contract that gives rise to a financial asset to one entity and a financial liability or equity instrument to another entity. Upon initial recognition, all financial instruments, including all derivatives, are recognized on the balance sheet at fair value. Subsequent measurement is then based on the financial instruments being classified into one of five categories: held for trading, held to maturity, loans and receivables, available for sale and other liabilities. The Company has designated its cash as held for trading which is measured at fair value. Accounts receivable are classified as loans and receivables which are measured at amortized cost. Accounts payable and accrued liabilities and bank loans are classified as other liabilities which are measured at amortized cost determined using the effective interest method.

The Company is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of operations. A variety of derivative instruments may be used by the Company to reduce its exposure to fluctuations in commodity prices, foreign exchange rates, and interest rates. The Company does not use these derivative instruments for trading or speculative purposes. The Company considers all of these transactions to be economic hedges, however, several of the Company's contracts do not qualify or have not been designated as hedges for accounting purposes. As a result, derivative contracts are classified as held for trading and are recorded on the balance sheet at fair value, with changes in the fair value recognized in earnings, unless specific hedge criteria are met. If specific hedge criteria are met, changes in the fair value are initially recognized in other comprehensive income and are subsequently reclassified to earnings in the same period in which the revenues associated with the hedged transactions are recognized. The fair values of these derivative instruments are based on an estimate of the amounts that would have been received or paid to settle these instruments prior to maturity given future market prices and other relevant factors.

The Company has elected to account for its physical delivery sales contracts, which were entered into and continue to be held for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements as executory contracts on an accrual basis rather than as non-financial derivatives.

The Company measures and recognizes embedded derivatives separately from the host contracts when the economic characteristics and risks of the embedded derivative are not closely related to those of the host contract, when it meets the definition of a derivative and when the entire contract is not measured at fair value. Embedded derivatives are recorded at fair value.

The Company nets all transaction costs incurred, in relation to the acquisition of a financial asset or liability, against the related financial asset or liability. Bank loans are presented net of deferred interest payments, with interest recognized in earnings on an effective interest basis.

The Company applies trade-date accounting for the recognition of a purchase or sale of cash equivalents and derivative contracts.

(k) 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.

(l) 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.

(m) Comparative figures

Certain comparative figures have been reclassified to conform to the current year's presentation.

2. Change in accounting policies

On January 1, 2007, the Company adopted the new Canadian accounting standards for financial instruments - recognition and measurement, financial instruments - presentation and disclosure, hedging and comprehensive income. Prior periods have not been restated. Adopting these standards had no impact on the measurement of existing financial assets and liabilities other than for the derivative discussed below.

The Company used financial derivatives to manage the price risk attributable to the anticipated sale of natural gas production to March 31, 2007 (see note 10). Prior to January 1, 2007, the Company applied hedge accounting to these financial derivatives. On adoption of the new standards, the Company discontinued hedge accounting for the financial derivatives held and the fair value of the financial derivatives was reflected in accounts receivable with the offset to accumulated other comprehensive income as allowed for on transition. These net gains were subsequently reclassified to earnings in 2007 in accordance with the terms of the derivatives.

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



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


Effective January 1, 2008, the Company will be required to adopt three new accounting standards: Section 1535 "Capital Disclosures", Section 3862 "Financial Instruments - Disclosures" and Section 3863 "Financial Instruments - Presentation". Section 1535 requires disclosure of an entity's objectives, policies and processes for managing capital, including: quantitative data about what the entity considers capital, whether the entity has complied with any capital requirements and the consequences of non-compliance if the entity has not complied. Sections 3862 and 3863 specify standards of presentation and enhanced disclosures on financial instruments. Although the Company is currently assessing the impact of these standards on its financial statements, it is not anticipated that the adoption of these new standards will impact the amounts reported in the Company's financial statements as they primarily relate to disclosure.

3. Acquisition of 3210700 Nova Scotia Company

On September 1, 2007, the Company completed the acquisition of certain oil and natural gas assets indirectly through the purchase of all of the issued and outstanding shares of a newly formed company, 3210700 Nova Scotia Company for aggregate cash consideration of $117.1 million ($117.6 million after adjustments and acquisition costs). The acquisition has been accounted for using the purchase method of accounting. The net revenues from the assets have been included with the results of the Company commencing September 1, 2007.

The purchase price has been allocated as follows:



------------------------------------------------------------
------------------------------------------------------------
Net assets at assigned values
------------------------------------------------------------
Property, plant and equipment $ 133,441
Deposits 241
Goodwill 21,044
Future income taxes (30,604)
Provision for loss on transportation contracts (565)
Asset retirement obligations (5,923)
------------------------------------------------------------
$ 117,634
------------------------------------------------------------
------------------------------------------------------------


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


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

4. Property, plant and equipment



------------------------------------------------------------
------------------------------------------------------------
2007 2006
------------------------------------------------------------
Cost $ 573,002 $ 342,529
Less accumulated depletion and
depreciation (111,106) (70,349)
------------------------------------------------------------
Net book value $ 461,896 $ 272,180
------------------------------------------------------------
------------------------------------------------------------


At December 31, 2007, unproved property costs of $16.1 million (2006 - $21.2 million) have been excluded from the full cost pool for depletion and depreciation calculations. Future development costs of proved, undeveloped reserves of $177.8 million (2006 - $101.5 million) have been included in the depletion and depreciation calculation.

For the year ended December 31, 2007, $3.4 million (2006 - $3.2 million) of general and administrative costs including $0.6 million (2006 - $0.3 million) of stock-based compensation costs were capitalized. The future tax liability of $0.2 million (2006 - $0.1 million) associated with the capitalized stock-based compensation has also been capitalized. Capitalized general and administrative costs consist of salaries and associated office rent of staff involved in capital activities.

No impairment was recognized under the ceiling test at December 31, 2007. 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 $6.90 per thousand cubic feet in 2008, $7.75 in 2009, $8.10 in 2010, $8.50 in 2011, $8.65 in 2012 and $9.10 in 2013. After 2013, only inflationary growth of 2% 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$85.00 per barrel in 2008, US$81.60 in 2009, US$81.15 in 2010, US$79.60 in 2011, US$77.95 in 2012 and US$77.30 in 2013. After 2013, only inflationary growth of 2% was considered. The foreign exchange rate was estimated to be 0.98 US$/Cdn$ in 2008, 0.95 in 2009, 0.92 in 2010 and 0.90 thereafter.

5. Bank loans

On September 4, 2007, the Company entered into a $95 million extendible, revolving term credit facility and a $10 million working capital credit facility (the "Facilities") with a syndicate of Canadian banks. The reserves-based Facilities have a revolving period ending on July 15, 2008, extendible at the option of the lenders, followed by a term period with three equal quarterly principle repayments commencing 180 days from the term date. Advances under the Facilities can be drawn in either Canadian or U.S. funds. The Facilities bear interest at the bank's prime lending rate, bankers' acceptance or LIBOR loan rates plus applicable margins. The margins vary depending on the borrowing option used and the Company's financial ratios. At December 31, 2007, there were no advances in U.S. funds. The average effective interest rate on advances in 2007 was 5.9% (2006 - 5.4%).

On January 17, 2008, the Company entered into a $25 million supplemental credit facility (the "Supplemental Facility") with the existing syndicate of Canadian banks. The Supplemental Facility is in addition to the Facilities noted above and is available on a revolving basis. The Supplemental Facility reduces to $10 million on September 30, 2008, and shall be repaid in full on or before December 31, 2008. Advances under the Supplemental Facility can be drawn in either Canadian or U.S. funds and bear interest at the bank's prime lending rate, bankers' acceptance or LIBOR loan rates plus applicable margins. The margins vary depending on the borrowing option used and the Company's financial ratios.

Loans are secured by a floating charge debenture over all assets and guarantees by material subsidiaries.

6. Asset retirement obligations

The Company estimates the total undiscounted cash flows required to settle its asset retirement obligations at December 31, 2007 is approximately $52.2 million (2006 - $27.7 million), including expected inflation of 2% per annum for each of 2007 and 2006. The majority of the costs will be incurred between 2008 and 2020. A credit adjusted risk-free rate of 8% was used to calculate the fair value of the asset retirement obligations at December 31, 2007 and 2006.

A reconciliation of the asset retirement obligations is provided below:



-------------------------------------------------------------------------
-------------------------------------------------------------------------
2007 2006
-------------------------------------------------------------------------
Balance, beginning of year $ 14,905 $ 11,299
Liabilities incurred during year 3,060 3,065
Liabilities assumed on corporate acquisition (note 3) 5,923 -
Liabilities settled in year (742) (405)
Accretion expense 1,380 946
-------------------------------------------------------------------------
Balance, end of year $ 24,526 $ 14,905
-------------------------------------------------------------------------
-------------------------------------------------------------------------


7. Taxes

The temporary differences that gave rise to the Company's future income tax liabilities (assets) at December 31, 2007 and 2006 were as follows:



-------------------------------------------------------------------------
-------------------------------------------------------------------------
2007 2006
-------------------------------------------------------------------------
Future income tax liabilities (assets):
Property, plant and equipment in excess of tax basis $ 45,012 $ 16,912
Asset retirement obligations (6,156) (4,358)
Share issue costs (2,578) (1,055)
Current income deferred 5,172 5,513
-------------------------------------------------------------------------
$ 41,450 $ 17,012
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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



-------------------------------------------------------------------------
-------------------------------------------------------------------------
2007 2006
-------------------------------------------------------------------------

Loss before taxes $ (6,336) $ (8,884)
Combined federal and provincial tax rates 32.24% 34.61%
-------------------------------------------------------------------------
Expected future income tax reduction (2,043) (3,075)
Increase (decrease) in income taxes resulting from:
Changes in expected future tax rates (6,684) (2,350)
Non-deductible stock based compensation and other 207 75
-------------------------------------------------------------------------
Future income tax reduction $ (8,520) $ (5,350)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


At December 31, 2007, the Company had loss carry forwards of $34 million that will expire between 2011 and 2027. The Company expects to be able to fully utilize these losses.

8. Share capital and contributed surplus

Authorized share capital

The Company is authorized to issue an unlimited number of common and preferred shares. The preferred shares may be issued in one or more series.



Issued share capital

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Number of
Common Amount
Shares (thousands)
----------------------------------------------------------------------------
Balance at December 31, 2005 47,967,708 $ 184,315
Issued on property acquisitions 943,791 6,768
Issue of private placement common shares (1) 1,091,703 5,000
Issue of flow-through common shares (1) 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 shares issued in 2005 - (3,382)
----------------------------------------------------------------------------
Balance at December 31, 2006 53,641,401 208,994
Issued pursuant to prospectuses (2) 33,635,000 134,747
Share issue costs - (7,537)
Tax effect of share issue costs - 2,329
Stock options exercised 18,000 72
Tax effect of flow-through shares issued in 2006 - (4,458)
----------------------------------------------------------------------------
Balance at December 31, 2007 87,294,401 $ 334,147
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes 1,091,703 common shares and 255,320 flow-through shares issued
to management and directors
(2) Includes 344,494 common shares shares issued to management and directors


Flow-through shares

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

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. As of December 31, 2007 the Company has incurred all of the qualifying expenditures.

Stock options

The Company has an employee stock option plan under which employees, directors and consultants are eligible to receive grants. The exercise price of stock options equals the weighted average trading price of the Company's shares for the five trading days prior to the date of the grant. Options have terms of either five or ten years and vest equally over a three year period starting on the first anniversary date of the grant. Changes in the number of options outstanding during the years ended December 31, 2007 and 2006 are as follows:



-----------------------------------------------------------------
-----------------------------------------------------------------
Number of Weighted average
options exercise price
-----------------------------------------------------------------
Balance at December 31, 2005 4,179,355 $ 4.95
Granted 1,544,100 5.26
Exercised (446,709) 4.35
Expirations and forfeitures (446,340) 7.25
-----------------------------------------------------------------
Balance at December 31, 2006 4,830,406 4.89
Granted 1,531,500 3.94
Exercised (18,000) 4.00
Expirations and forfeitures (46,600) 7.28
-----------------------------------------------------------------
Balance at December 31, 2007 6,297,306 $ 4.65
-----------------------------------------------------------------
-----------------------------------------------------------------
Exercisable at December 31, 2007 3,635,139 $ 4.66
-----------------------------------------------------------------
-----------------------------------------------------------------



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

Weighted Weighted Weighted
average average average
Range of Number exercise remaining Number of exercise
exercise prices of options price life (years) options price
------------------ ---------------------------------- --------------------
$3.67 to $5.00 5,028,706 $ 4.00 4.5 2,945,006 $ 4.01
$5.01 to $7.50 543,200 6.17 3.5 237,800 6.29
$7.51 to $9.01 725,400 8.01 2.8 452,333 8.04
---------------------------------- --------------------
Total at
December 31, 2007 6,297,306 $ 4.65 4.2 3,635,139 $ 4.66
---------------------------------- --------------------
---------------------------------- --------------------


The fair value of the options issued in 2007 ranged between $1.55 to $1.99 (2006 - $1.51 to $2.07) per option. The weighted average assumptions used in arriving at these values were: a risk-free interest rate of between 4.0% to 4.4% (2006 - 3.9% to 4.5%), expected option life of four years, expected volatility of between 40% to 50% (2006 - 25% to 40%) and a dividend yield of 0%.

Per share amounts

During the year ended December 31, 2007 there were 67,793,774 weighted average shares outstanding (2006 - 50,164,782). On a diluted basis, there were 67,846,897 weighted average shares outstanding (2006 - 50,164,782) after giving effect to dilutive stock options. At December 31, 2007, there were 2,249,100 (2006 - 4,830,406) options that were anti-dilutive.

Contributed surplus



-----------------------------------------------------------------------
-----------------------------------------------------------------------
Amount
-----------------------------------------------------------------------
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
Stock-based compensation 1,185
-----------------------------------------------------------------------
Balance at December 31, 2007 $ 2,005
-----------------------------------------------------------------------
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Accumulated other comprehensive income

As described in note 2, the adoption of the new Canadian accounting standards for financial instruments resulted in an amount being recognized in accumulated other comprehensive income for the fair value at January 1, 2007 of the Company's financial derivatives to manage the price risk attributable to the anticipated sale of natural gas production. The amount recognized in accumulated other comprehensive income was $1.5 million, representing the value of the asset of $2.2 million net of future income taxes of $0.7 million. The amount was reclassified resulting in an increase in earnings over the term of the contracts with a corresponding decrease to other comprehensive income.



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2007 2006
Accumulated other comprehensive income, beginning of year $ - $ -
Fair value of financial derivatives on transition to new
accounting standards (net of tax of $695) 1,465 -
Reclassification to earnings (net of tax of $695) (1,465) -
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Accumulated other comprehensive income, end of year $ - $ -
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9. Cash payments

The following cash payments were paid (received):



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2007 2006
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Interest paid $ 3,071 $ 1,699
Interest received (299) (68)
Taxes paid - 294

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10. Financial instruments

The Company's financial instruments include cash, accounts receivable and accruals, deposits, accounts payable and accruals and bank loans. The carrying value of accounts receivable and accruals, deposits and accounts payable and accruals approximate their fair value due to their demand nature or relatively short periods to maturity. The fair value of bank loans approximates the carrying value as they bear interest at a floating rate.

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.

The Company is exposed to interest rate risk to the extent that bank loans are at a floating rate of interest.

In 2007, the Company entered into certain fixed price natural gas financial swap contracts to manage commodity price risk. The gains realized in 2007 were $1.2 million and have been included in oil and gas sales. There were no commodity price risk contracts outstanding at December 31, 2007.

On January 10, 2008, the Company entered into physical sales contracts to sell 25,000 GJ/day for February and March 2008 at an average AECO price of $6.89/GJ.

11. Related party transactions

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

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.

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 properties of Aquest Energy Ltd., a Company purchased by Anderson Energy in 2005. 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.

12. Commitments

The Company has entered into an agreement to lease office space until November 2012. Future minimum lease payments are expected to be $1.8 million in 2008 through 2011 and $1.6 million in 2012.

The Company entered into firm service transportation agreements for approximately 25 million cubic feet per day of gas sales in central Alberta for various terms expiring in one to eight years.



Corporate Information Contact Information
Head Office
700 Selkirk House Anderson Energy Ltd.
555 4th Avenue S.W. Brian H. Dau
Calgary, Alberta President & Chief Executive Officer
Canada T2P 3E7 (403) 206-6000
Phone (403) 262-6307
Fax (403) 261-2792
Website www.andersonenergy.ca


Directors Officers

J.C. Anderson (1)(2) J.C. Anderson
Calgary, Alberta Chairman of the Board

Brian H. Dau Brian H. Dau
Calgary, Alberta President & Chief Executive Officer

Vincent L. Chahley (1)(2)(3) M. Darlene Wong
Calgary, Alberta Vice President Finance, Chief Financial
Officer & Secretary
Glenn D. Hockley (3)
Calgary, Alberta Blaine M. Chicoine
Vice President, Operations
David G. Scobie (1)(2)(3)
Calgary, Alberta Philip A. Harvey
Vice President, Exploitation
Member of:
(1) Audit Committee Daniel F. Kell
(2) Compensation & Corporate Vice President, Land
Governance Committee
(3) Reserves Committee David M. Spyker
Vice President, Business Development

Auditors
KPMG LLP
Calgary, Alberta

Independent Engineers
AJM Petroleum Consultants

Legal Counsel
Bennett Jones LLP

Registrar & Transfer Agent
Valiant Trust Company

Stock Exchange
The Toronto Stock Exchange
Symbol AXL

Abbreviations used:

AECO - intra-Alberta Nova inventory transfer price
bbl - barrel
bpd - barrels per day
Mbbls - thousand barrels
BOE - barrels of oil equivalent
BOED - barrels of oil equivalent per day
MBOE - thousand barrels of oil equivalent
MMBOE - million barrels of oil equivalent
CBM - Coal Bed Methane
GJ - gigajoule
Mcf - thousand cubic feet
Mcfd - thousand cubic feet per day
MMcf - million cubic feet
MMcfd - million cubic feet per day
Bcf - billion cubic feet


Contact Information

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