Anderson Energy Ltd.
TSX : AXL

Anderson Energy Ltd.

May 11, 2006 22:53 ET

Anderson Energy Ltd. Announces First Quarter 2006 Results

CALGARY, ALBERTA--(CCNMatthews - May 11, 2006) - Anderson Energy Ltd., ("Anderson Energy" or "the Company") (TSX:AXL) is pleased to announce its operating and financial results for the first quarter ended March 31, 2006.

Highlights:

- First quarter production averaged 4,081 BOED, an increase of 10% over the fourth quarter of 2005 and 194% over the comparable quarter of 2005. Current production is approximately 4,800 BOED, and production behind pipe is approximately 700 BOED.

- As of March 31, 2006, the Company's drilling inventory is 879 gross (324.9 net) wells. The Edmonton Sands play represents 59% of the net inventory and Horseshoe Canyon coal bed methane projects represent 31% of the net inventory. Since December 31, 2005, the Company has increased its Edmonton Sands drilling inventory by 63 gross (51.8 net) locations.

- Cash flow from operations in the first quarter of 2006 is $8.6 million or $0.18 per share, a decrease of $4.6 million or $0.10 per share over the fourth quarter of 2005 and an increase of $6.0 million over the first quarter of 2005.

- The average natural gas price for the first quarter was $7.40/Mcf, which is $3.99/Mcf lower than the fourth quarter of 2005 and $0.44/Mcf higher than the first quarter of 2005.

- Drilling for the three months ended March 31, 2006 resulted in 38 gross (18.3 net) wells drilled with a success rate of 92%.

- The Company has completed 8 acquisition and disposition property consolidation transactions to date in 2006 by issuing 576,394 shares, and receiving net proceeds of $0.8 million in cash. Net F&D&A costs on acquisition and disposition transactions were $17.48/BOE proved and $11.84/BOE proved and probable including future development capital.



Financial and Operating Highlights
Three months ended %
March 31 Change
------------------
2006 2005
------------------
Financial
(thousands of dollars, except share data)

Total oil and gas revenue $ 16,889 $ 5,266 221%

Cash flow from operations $ 8,604 $ 2,581 233%
Per common share - basic $ 0.18 $ 0.08 125%
- diluted $ 0.17 $ 0.07 143%
Net earnings (loss) (1,196) (773) (55%)
Per common share - basic $ ( 0.02) $ (0.02) 0%
- diluted $ ( 0.02) $ (0.02) 0%

Capital expenditures 33,720 20,545 64%
Debt, net of working capital 43,042 436 (9772%)

Shareholders' equity 185,678 98,482 89%

Average shares outstanding (thousands)
Basic 48,274 33,581 44%
Diluted 49,674 34,505 44%

Ending shares outstanding (thousands) 48,900 33,625 45%

Operating (6 Mcf:1bbl conversion)

Average daily sales
Natural gas (Mcfd) 20,799 8,165 155%
Light/medium crude oil (bpd) 462 6 7600%
NGL (bpd) 152 22 591%
Barrels of oil equivalent (BOED) 4,081 1,389 194%

Average sales price
Natural gas ($/Mcf) 7.40 6.96 6%
Light/medium crude oil ($/bbl) 51.37 60.76 (15%)
NGL ($/bbl) 50.50 50.26 0%
Barrels of oil equivalent ($/BOE) 45.41 41.96 8%

Royalties ($/BOE) 10.38 8.74 19%
Operating costs ($/BOE) 8.57 7.43 15%
Operating netbacks ($/BOE) 27.04 25.96 4%
General and administrative ($/BOE) 3.15 6.23 (49%)

Wells drilled (gross) 38 26 46%


Production:

First quarter production was slightly less than anticipated due to delays in well tie-ins and AEUB holding approvals. From March 25, 2006 to April 1, 2006 there was also a NOVA outage that reduced gas sales in the Sylvan Lake area by 3 MMcfd. During the quarter, the Company completed two significant facility projects, one at Tindastol in the Sylvan Lake area and the second at Teepee in the Peace River Arch. The Tindastol compression project was completed on February 9, 2006. By the end of the quarter, the Company was able to tie-in new wells and restart wells shut-in awaiting AEUB holding approval. This compression is key to the Company's plans to tie-in further wells drilled in the first quarter and planned drilling this summer. The Teepee field compression project was completed on March 3, 2006 and increased the Company's share of production by 1.3 MMcfd.

As of late April, the Company's current production is approximately 4,800 BOED. The Company has approximately 700 BOED of production behind pipe, which is expected to be onstream in the third and fourth quarters subject to regulatory and landowner approvals. The Company added additional staff in the first quarter to reduce the cycle time from discovery to first production and is starting to see the results from those efforts.

Operations:

In the first quarter, the Company spent $33.7 million in capital, of which $3.7 million was expended on net property acquisitions. The Company drilled 38 gross (18.3 net) wells in the first quarter of 2006 with a success rate of 92%.

In the Sylvan Lake area, the Company drilled 18 gross (9.4 net) gas wells.

The capital spent in the northeast BC program was a total of $3.9 million. The Company drilled one 39% working interest successful development gas well and one exploratory dry hole at Chinchaga as well as three Sierra Kakisa horizontal gas wells. These wells are now on production.

At Wimborne, the Company drilled a 57% working interest Belly River gas well which tested at 1 MMcfd. This well should be tied-in shortly after spring breakup. The well also has uphole Edmonton Sands and Horseshoe Canyon coals and the Company is planning to twin this well in the third quarter. The Company drilled 4 gross (2.5 net) oil wells in Provost which should be onstream after spring breakup. In the Greencourt property, the Company drilled one gross (0.6 net) well, that will be completed after breakup. The Company participated in 7 gross (2.1 net) Horseshoe Canyon coal bed methane wells in the first quarter.

Acquisitions and Dispositions:

As of May 11 2006, the Company has completed five property acquisition transactions for $4.5 million by issuing 576,394 common shares as consideration. Four of the transactions were producing property acquisitions where the Company acquired a partner minority interest in petroleum and natural gas assets in the former Aquest properties. The fifth transaction was an undeveloped land acquisition in the Ghost Pine CBM project area. A sixth transaction was completed for cash totaling $2.4 million where the Company acquired production and undeveloped land in the Sylvan Lake area. The Company sold two properties in the first quarter of the year for total cash consideration of $3.1 million. The most significant property sold was Clarke Lake. F&D&A (including future development capital) for the total of all of the acquisition and disposition activity was $17.48 per BOE proved, $11.84 per BOE proved and probable, including changes to future development capital. Net production acquired was 109 BOED for a net acquisition cost of $34,200/BOED. Through these transactions, the Company added 14.8 net drilling locations and simplified its working interests in a number of assets acquired as part of the Aquest Energy corporate acquisition in 2005.

Outlook:

As of March 31, 2006, the Company has assembled a drilling inventory of 879 gross (324.9 net) locations on its lands. Approximately 59% of the net locations are Edmonton Sands prospective, 31% are Horseshoe Canyon CBM development locations and the balance is distributed amongst the rest of the Company's projects. This represents a five year drilling inventory. Since December 31, 2005, the Company has increased its Edmonton sand drilling inventory by 63 gross (51.8 net) locations.

The warm winter conditions in January had a negative impact on natural gas prices in the first quarter of 2006, as well as projected summer North American natural gas prices. The levels of natural gas storage heading into the summer injection season are at historic highs and natural gas prices may be soft until next winter. While the Company continues to be bullish on the long term prospects for natural gas, North American weather conditions, the geopolitics of crude oil pricing and North American production declines will determine summer gas prices. However at the end of the natural gas storage injection season, natural gas storage can be no more than full. When winter returns, natural gas prices should have strengthened.

The Company will continue to develop its Edmonton Sands drilling opportunities, evaluate its CBM acreage and continue with some of its North Central and Eastern Alberta drilling programs. In the balance of the year, the Company expects to participate in 67 gross (13 net) Horseshoe Canyon coal bed methane locations in its Tier 1 area. The Company will be evaluating with the drillbit, two high impact Horseshoe Canyon coal bed methane projects at Pearce (42% working interest in 36,312 acres) and Blood (100% working interest in 50,880 acres). As well, the Company will likely consolidate some of its interest on the Aquest properties through further acquisitions and dispositions. The Company has one property disposition totaling $2.2 million which is expected to close within 90 days.

The Company has positioned itself, with an increase in its bank line to $55 million, and property sales, to increase its capital spending when gas prices strengthen.

We invite our shareholders to attend the Company's first annual & general meeting as a public company on May 12, 2006 at the Metropolitan Centre in Calgary at 10:00 AM.

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



(signed)

Brian H. Dau
President and Chief Executive Officer
May 11, 2006


Management's Discussion and Analysis For the Three Months Ended

March 31, 2006 and 2005:

The following discussion and analysis of financial results should be read in conjunction with the unaudited interim consolidated financial statements of Anderson Energy Ltd. ("Anderson Energy" or "the Company") for the three months ended March 31, 2006 and 2005 and is based on information available as of May 11, 2006.

The following information has been prepared by management in accordance with Canadian generally accepted accounting principles ("GAAP"). Production and reserve numbers are stated before deducting crown or lessor royalties. Included in the discussion and analysis are references to terms commonly used in the oil and gas industry such as cash flow from operations and barrel of oil equivalent. Cash flow from operations as used in this report represent funds from operating activities before changes in non-cash working capital and asset retirement expenditures. Anderson Energy believes that cash flow from operations represent both an indicator of the Company's performance and a funding source for on-going operations. Production volumes and reserves are commonly expressed on a 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.

The information contained herein contains forward looking statements and assumptions, such as those relating to results of operations and financial condition, capital spending, financial resources, commodity prices and costs of production. By their nature, forward looking statements are subject to numerous risks and uncertainties that could significantly affect anticipated results in the future and, accordingly, actual results may differ materially from those predicted. The forward looking statements contained herein are as of May 11, 2006 and are subject to change after this date. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward looking statements.

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

Review of Financial Results:

First quarter sales volumes were within 2% of the Company's budget. Commodity prices declined in the first quarter but prices and expenses were in line with expectations. Debt, net of working capital, was higher than budgeted due to capital expenditures made in the quarter. Field capital expenditures were higher than budgeted, as the Company took advantage of a later than anticipated spring breakup to drill more wells than originally planned, and incurred approximately $1.5 million in additional expenditures related to equipment procurement and lease preparation for an anticipated busy drilling program in the second and third quarters.

Revenue and Production:

Gas sales made up 82% of Anderson Energy's total oil and gas sales for the three months ended March 31, 2006 compared to 86% of total oil and gas sales for the fourth quarter of 2005 and 97% of total oil and gas sales for the three months ended March 31, 2005.

The Company achieved average gas sales of 20.8 MMcfd in the first quarter of 2006. This compares to 18.8 MMcfd in the fourth quarter of 2005 and 8.2 MMcfd in the first quarter of 2005. Sales volume increases are primarily attributable to new wells being tied-in in the quarter. Sales volumes were negatively impacted by an unexpected NOVA outage in the last week of March which resulted in approximately 3 MMcfd of gas sales being shut-in temporarily.

Oil production averaged 462 bpd in the first quarter of 2006 as compared to 409 bpd in the fourth quarter of 2005 and 6 bpd in the first quarter of 2005. Natural gas liquids production averaged 152 bpd in the first quarter of 2006 as compared to 168 bpd in the fourth quarter of 2005 and 22 bpd in the first quarter of 2005.

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



Three months ended March 31
-----------------------------
2006 2005
Oil and Natural Gas Revenue
(thousands of dollars)
Natural Gas $ 13,852 $ 5,114
Oil 2,138 30
NGL 691 101
Royalty and other 208 21
-----------------------------------------------------------------------
Total $ 16,889 $ 5,266
-----------------------------------------------------------------------

Three months ended March 31
-----------------------------
2006 2005
Production
Natural gas (Mcfd) 20,799 8,165
Oil (bpd) 462 6
NGL (bpd) 152 22
-----------------------------------------------------------------------
Total (BOED) 4,081 1,389
-----------------------------------------------------------------------

Three months ended March 31
-----------------------------
2006 2005
Prices
Natural gas ($/Mcf) 7.40 6.96
Oil ($/bbl) 51.37 60.76
NGL ($/bbl) 50.50 50.26
-----------------------------------------------------------------------
Total ($/BOE) 45.41 41.96
-----------------------------------------------------------------------


Anderson Energy's average gas sales price was $7.40/Mcf for the three months ended March 31, 2006. This compares to $11.39/Mcf realized in the fourth quarter of 2005 and $6.96/Mcf realized in the first quarter of 2005.

Anderson Energy sells most of its gas at Alberta spot market prices and has not entered into any fixed price or forward contracts for the sale of its production. 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.

Royalties:

Royalties were 23% of the revenue in the first quarter of 2006, 24% of revenue in the fourth quarter of 2005 and 21% of revenue in the first quarter of 2005. The Company expects 2006 royalties to increase overall as production increases. The average royalty rate on a percentage basis should be similar to the current quarter.

Operating Expenses:

Operating expenses were $8.57/BOE in the first quarter of 2006, $8.47/BOE for the fourth quarter of 2005 and $7.43/BOE for the first quarter of 2005. Operating costs are expected to increase overall as production increases. Operating costs may increase on a BOE basis as well due to the increasing cost of doing business in western Canada.



Operating Netback:

Three months ended March 31
-----------------------------
2006 2005
(thousands of dollars)
Revenue $ 16,889 $ 5,266
Royalties (3,814) (1,092)
Operating expenses (3,148) (929)
-----------------------------
$ 9,927 $ 3,245
-----------------------------

Sales (MBOE) 367.3 125.0

($/BOE)
Revenue $ 45.98 $ 42.13
Royalties (10.38) (8.74)
Operating expenses (8.57) (7.43)
-----------------------------
$ 27.04 $ 25.96
-----------------------------


General and Administrative Expenses:

General and administrative expenses were $3.15/BOE in the first quarter of 2006, $3.51/BOE in the fourth quarter of 2005 and $6.23/BOE in the first quarter of 2005. It is expected that overall general and administrative expenses will increase as a result of increased staffing levels to manage the growth in drilling activity. General and administrative expenses consist largely of salaries, rent, computer and other office costs. As the Company increases its production in the upcoming quarters, general and administrative costs on a per BOE basis are expected to continue to decline.



Three months ended March 31
-----------------------------
2006 2005

General and administrative (gross) $ 2,620 $ 1,096
Overhead recoveries (695) (112)
Capitalized (767) (201)
------------------------------------------------------------------------
General and administrative (net) $ 1,158 $ 783
------------------------------------------------------------------------

General and administrative ($/BOE) $ 3.15 $ 6.23

% G&A capitalized 29% 18%


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

Interest Expense:

Interest expense was $0.2 million in the first quarter of 2006. Interest expense is expected to increase in future quarters as a result of higher debt levels associated with the Company's capital program and higher interest rates.

Depletion, Depreciation and Amortization:

Depletion and depreciation was $26.98/BOE in the first quarter of 2006, $28.60/BOE for the fourth quarter of 2005 and $28.96/BOE for the first quarter of 2005. Depletion and depreciation expense is calculated based on proved reserves only and is significantly impacted by the fact that only 53% of the Company's total reserves as of March 31, 2006 are proved reserves. The ratio reflects the newness of the wells that make up the reserve evaluation. Given expected production increases for the balance of the year, the Company expects depletion and depreciation expense to remain high for the remainder of the year.

Asset Retirement Obligation:

As a result of new drilling, the Company incurred $0.7 million in asset retirement obligations in the first quarter of 2006. Accretion expense was $0.2 million for the first three months of the year and was included in depletion and depreciation expense.

Income Taxes:

The Company is not currently taxable except for large corporations tax. The Company has approximately $172 million in available tax pools as of March 31, 2006.

The subscription receipts financing completed on September 1, 2005 included $10 million of flow through shares. The flow though share renouncements were made on February 28, 2006 for qualifying exploration expenditures that will be incurred between September 1, 2005 and December 31, 2006.

Cash Flow from Operations:

Cash flow from operations for the three months ended March 31, 2006 was $8.6 million.

Earnings:

The Company reported a $1.2 million loss in the first quarter of 2006. The Company does not expect to be able to report significant earnings until it can convert more of its probable reserves to proved reserves. A large portion of the Company's capital spending is directed at developing probable undeveloped reserves in 2006.

Capital Expenditures:

The Company spent $33.7 million in capital additions for the first quarter of 2006. The breakdown of expenditures is shown below:



Three months ended
(thousands of dollars) March 31, 2006
-------------------

Land, geological & geophysical costs $ 2,824
Property acquisitions net of dispositions 3,707
Drilling, completion and recompletion 16,526
Facilities and well equipment 9,114
Office equipment and furniture 70
Capitalized G&A 767
Asset retirement costs 712
-------------------
Total $ 33,720
-------------------


In addition, a gross-up of capital costs and an associated future income tax liability of $2.3 million were recorded to reflect the fact that the property acquisitions for shares included minimal tax pools.



Drilling statistics are shown below:

Three months ended March 31
-----------------------------
2006 2005
Gross Net Gross Net
Gas 30.0 13.0 24.0 15.7
Oil 5.0 3.1 1.0 0.5
Dry 3.0 2.2 1.0 1.0
-----------------------------
Total 38.0 18.3 26.0 17.2
-----------------------------

Success rate (%) 92% 88% 96% 94%


For the first quarter of 2006, 50% of the gross wells drilled were in Sylvan Lake.

Liquidity and Capital Resources:

The Company expects to spend $28 million in field capital in the rest of 2006. The Company's cash flow and bank lines are adequate to fund the program.

In May 2006, the Company renewed its revolving credit facility increasing the borrowing base to $55 million. The reserve-based credit facility has a revolving period ending July 15, 2007, extendible at the option of the lender, followed by a term period with three equal quarterly principle repayments commencing 180 days from the term date. The facility bears interest at the bank's prime lending rate, bankers' acceptance or LIBOR rates plus applicable margins. Loans are secured by a floating charge debenture over all assets and guarantees by material subsidiaries.

As of May 11, 2006, there are 48.9 million common shares outstanding and 4.0 million stock options outstanding.

Business Risks:

Oil and gas exploration and production is capital intensive and involves a number of business risks including the uncertainty of finding new reserves, the instability of commodity prices and various operational risks. Commodity prices are influenced by local and worldwide supply and demand, the U.S. dollar exchange rate, transportation costs, political stability and seasonal and weather related changes to demand. The industry is subject to extensive governmental regulation with respect to the environment.

The Company manages these risks by employing competent professional staff, following sound operating practices and using capital prudently. The Company generates its exploration prospects internally and performs extensive geological, geophysical, engineering, and environmental analysis before committing to the drilling of new prospects. The Company seeks out and employs new technologies where possible.

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

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

Business Prospects:

The Company has an excellent drilling inventory with over five years of development drilling locations at Sylvan Lake and Sierra. The Company is in the midst of a significant drilling program at Sylvan Lake that is designed to increase production, move probable reserves to proved reserves and add additional reserves. The Company is also evaluating its coal bed methane prospective acreage with active development and exploratory drilling.

Timing of AEUB regulatory applications continues to be slower than expected. Anderson Energy has incorporated these regulatory timing issues into its planning cycle. Competition for industry services is more intense than previous years and that, combined with more landholder consultations, requires more lead time and more planning. Given the Company's extensive drilling inventory, we have been able to meet this challenge through advance planning of larger scale drilling programs and securing the services of drilling rigs and sourcing people for larger projects.

The Company's estimate for 2006 average production remains at 5,000 to 5,400 BOED. Risks associated with this estimate include gas plant capacity, regulatory issues, weather problems and access to industry services.



Quarterly Information:

(in thousands, except per share amounts)

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

Oil & gas revenue before royalties $16,889 $22,894 $12,147 $ 6,646
Cash flow from operations $ 8,604 $13,187 $ 6,745 $ 2,942
Cash flow from operations per share
Basic $ 0.18 $ 0.28 $ 0.18 $ 0.09
Diluted $ 0.17 $ 0.27 $ 0.17 $ 0.09
Earnings (loss) $(1,196) $ 1,762 $ 543 $ (801)
Earnings (loss) per share
Basic $ (0.02) $ 0.04 $ 0.01 $ (0.02)
Diluted $ (0.02) $ 0.04 $ 0.01 $ (0.02)
Capital expenditures $33,720 $25,634 $14,960 $11,589
Daily sales
Natural gas (Mcfd) 20,799 18,785 11,991 9,623
Liquids (bpd) 614 577 250 50
BOE (bpd) 4,081 3,708 2,249 1,653
Average prices
Natural gas ($/Mcf) $ 7.40 $ 11.39 $ 9.68 $ 7.28
Liquids ($/bbl) $ 51.15 $ 53.56 $ 61.97 $ 54.59
BOE ($/BOE) $ 45.41 $ 66.05 $ 58.49 $ 43.98

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

Oil & gas revenue before royalties $ 5,266 $ 4,170 $ 3,147 $ 4,234
Cash flow from operations $ 2,581 $ 2,132 $ 1,369 $ 2,224
Cash flow from operations per share
Basic $ 0.08 $ 0.07 $ 0.05 $ 0.08
Diluted $ 0.07 $ 0.07 $ 0.05 $ 0.08
Earnings (loss) $ (773) $ (766) $ (323) $ 41
Earnings (loss) per share
Basic $ (0.02) $ (0.03) $ (0.01) $ 0.00
Diluted $ (0.02) $ (0.03) $ (0.01) $ 0.00
Capital expenditures $20,545 $16,063 $14,035 $ 3,677
Daily sales
Natural gas (Mcfd) 8,165 6,799 5,450 6,415
Liquids (bpd) 28 25 21 22
BOE (bpd) 1,389 1,159 929 1,092
Average prices
Natural gas ($/Mcf) $ 6.96 $ 6.47 $ 6.08 $ 7.10
Liquids ($/bbl) $ 52.34 $ 51.19 $ 50.87 $ 44.46
BOE ($/BOE) $ 41.96 $ 39.08 $ 36.80 $ 42.62


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

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

Assets

Current assets:
Cash and short-term investments $ 409 $ 510
Accounts receivable and accruals 30,916 31,303
Prepaid expenses and deposits 1,821 1,562
------------------------------------------------------------------------
33,146 33,375

Property, plant and equipment (note 1) 247,808 221,717

Goodwill 14,320 14,320
------------------------------------------------------------------------
$ 295,274 $ 269,412
------------------------------------------------------------------------
------------------------------------------------------------------------

Liabilities and Shareholders' Equity

Current liabilities:
Accounts payable and accruals $ 50,522 $ 46,420
Capital taxes payable 288 184
------------------------------------------------------------------------
50,810 46,604

Bank loan (note 3) 25,378 11,368

Asset retirement obligations (note 2) 12,142 11,299

Future income taxes 21,266 16,073
------------------------------------------------------------------------
109,596 85,344

Shareholders' equity:
Share capital (note 4) 186,978 184,315
Contributed surplus (note 4) 246 103
Deficit (1,546) (350)
------------------------------------------------------------------------
185,678 184,068

------------------------------------------------------------------------
$ 295,274 $ 269,412
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.


Consolidated Statements of Earnings (Loss) and Retained Earnings
(Deficit)
(unaudited)
(stated in thousands of dollars, except per share amounts)

------------------------------------------------------------------------
------------------------------------------------------------------------
Three months ended
March 31,
2006 2005
------------------------------------------------------------------------

Revenues
Oil and gas sales $ 16,889 $ 5,266
Royalties (net of ARTC of
$125 in 2006, $125 in
2005) (3,814) (1,092)
Interest income 9 140
------------------------------------------------------------------------
13,084 4,314

Expenses
Operating 3,148 929
General and administrative 1,158 783
Interest and other financing charges 228 -
Depletion, depreciation and
accretion 10,126 3,663
------------------------------------------------------------------------
14,660 5,375

------------------------------------------------------------------------
Loss before income taxes (1,576) (1,061)

Taxes
Capital taxes 90 22
Future income taxes (reduction) (470) (310)
------------------------------------------------------------------------
(380) (288)
------------------------------------------------------------------------
Loss for the period (1,196) (773)

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

------------------------------------------------------------------------
Deficit, end of period $ (1,546) $ (1,854)
------------------------------------------------------------------------
------------------------------------------------------------------------
Earnings (loss) per share
Basic $ (0.02) $ (0.02)
Diluted $ (0.02) $ (0.02)

See accompanying notes to consolidated financial statements.


Consolidated Statements of Cash Flows
(unaudited)
(stated in thousands of dollars)

------------------------------------------------------------------------
------------------------------------------------------------------------
Three months ended
March 31,
2006 2005
------------------------------------------------------------------------
Cash provided by (used in):

Operations
Loss for the period $ (1,196) $ (773)
Items not involving cash
Depletion, depreciation and accretion 10,126 3,663
Future income taxes (reduction) (470) (310)
Stock based compensation 144 1
Asset retirement expenditures (85) (160)
Changes in non-cash working capital
Accounts receivable and accruals 1,482 24
Prepaid expenses and deposits (52) (54)
Accounts payable and accruals (1,101) 271
Capital taxes payable 104 2
------------------------------------------------------------------------
8,952 2,664

Financing
Increase in bank loan 14,010 -
Issue of common shares 1,581 240
------------------------------------------------------------------------
15,591 240

Investments
Additions to property, plant and equipment (31,683) (19,816)
Proceeds on sale of properties 3,138 -
Changes in non-cash working capital
Accounts receivable and accruals (1,095) 11
Prepaid expenses and deposits (207) (22)
Accounts payable and accruals 5,203 6,682
------------------------------------------------------------------------
(24,644) (13,145)

------------------------------------------------------------------------
Decrease in cash and short-term
investments (101) (10,241)

Cash and short-term investments,
beginning of period 510 29,242
------------------------------------------------------------------------
Cash and short-term investments,
end of period $ 409 $ 19,001
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to consolidated financial statements

ANDERSON ENERGY LTD.
Notes to the Unaudited Interim Consolidated Financial Statements

For the three month periods ended March 31, 2006 and 2005
(tabular amounts in thousands of dollars, unless otherwise stated)


Anderson Energy Ltd. ("Anderson Energy" or "the Company") is engaged in the acquisition, exploration and development of oil and gas properties in western Canada. These interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the consolidated financial statements for the year ended December 31, 2005. The disclosures included below are incremental to those included with the annual consolidated financial statements. These interim consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto for the year ended December 31, 2005.



1. Property, plant and equipment:

------------------------------------------------------------------------
------------------------------------------------------------------------
March 31, December 31,
2006 2005
------------------------------------------------------------------------
Cost $ 291,290 $ 255,289
Less accumulated depletion
and depreciation (43,482) (33,572)
------------------------------------------------------------------------
Net book value $ 247,808 $ 221,717
------------------------------------------------------------------------
------------------------------------------------------------------------


At March 31, 2006, unproved property costs of $24.7 million (December 31, 2005 - $22.6 million) have been excluded from the full cost pool for depletion and depreciation calculations. Future development costs of proved, undeveloped reserves of $66.3 million (December 31, 2005 - $73.5 million) have been included for depletion, depreciation and impairment test calculations.

For the three months ended March 31, 2006, $767,000 (March 31, 2005 - $201,000) of general and administrative costs were capitalized. Capitalized general and administrative costs consist of salaries and associated office rent of staff involved in capital activities.

No impairment was recognized under the ceiling test at March 31, 2006. The future commodity prices used in the ceiling test were based on commodity price forecasts adjusted for differentials specific to the reserves.

2. Asset retirement obligations:

The Company estimates the total undiscounted cash flows required to settle its asset retirement obligations is approximately $22.0 million, including expected inflation of 2% per annum. The majority of the costs will be incurred between 2006 and 2016. A credit adjusted risk-free rate of 8% was used to calculate the fair value of the asset retirement obligations.

A reconciliation of the asset retirement obligations is provided below:



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

Balance, beginning of period $ 11,299 $ 2,094
Liabilities incurred during period 712 3,338
Liabilities assumed on
Aquest Energy acquisition - 5,822
Liabilities settled in period (85) (310)
Accretion expense 216 355
------------------------------------------------------------------------
$ 12,142 $ 11,299
------------------------------------------------------------------------
------------------------------------------------------------------------


3. Bank loan:

In May 2006, the Company renewed its revolving credit facility with a Canadian bank, increasing the borrowing base to $55 million. The reserve-based credit facility has a revolving period ending July 15, 2007, extendible at the option of the lender, followed by a term period with three equal quarterly principle repayments commencing 180 days from the term date. Advances under the facility can be drawn in either Canadian or U.S. funds. The facility bears interest at the bank's prime lending rate, bankers' acceptance or LIBOR loan rates plus applicable margins. The margins vary depending on the borrowing option used and the Company's financial ratios. Loans are secured by a floating charge debenture over all assets and guarantees by material subsidiaries.

4. Share capital and contributed surplus:

Authorized share capital

The Company is authorized to issue an unlimited number of common shares.

The Company is authorized to issue an unlimited number of 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
Stock options exercised 356,224 1,581
Transferred from contributed surplus
on stock option exercises 1
Tax effect of flow-through
share renouncements - (3,382)
Issued on property acquisitions 576,394 4,463
------------------------------------------------------------------------
Balance at March 31, 2006 48,900,326 $186,978
------------------------------------------------------------------------


Flow-through shares

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

The Company has an employee stock option plan under which employees, directors and consultants are eligible to receive grants. Changes in the number of options outstanding during the three month period ended March 31, 2006 are as follows:



------------------------------------------------------------------------
------------------------------------------------------------------------
Balance at December 31, 2005 4,179,355
Granted 412,200
Exercised (356,224)
Expirations and cancellations (139,500)
------------------------------------------------------------------------
Balance at March 31, 2006 4,095,831
------------------------------------------------------------------------
------------------------------------------------------------------------


The outstanding options at March 31, 2006 had an average exercise price of $5.13 and a weighted average remaining contractual life of 5.9 years; 2,642,931 of the options were exercisable at that date.

The fair value of the options issued in 2006 ranged between $1.61 to $2.07 per option. The weighted average assumptions used in arriving at these values were: a risk-free interest rate of 4.0%, expected option life of 4 years, expected volatility of 25% and a dividend yield of 0%.

Per share amounts

During the period ended March 31, 2006 there were 48,273,605 weighted average shares outstanding (March 31, 2005 - 33,581,334). On a diluted basis, there were 49,673,943 weighted average shares outstanding (March 31, 2005 - 34,504,979) after giving effect to dilutive stock options.



Contributed surplus

------------------------------------------------------------------------
------------------------------------------------------------------------
Amount
------------------------------------------------------------------------
Balance at December 31, 2005 $ 103
Stock based compensation 144
Transferred from contributed surplus on stock option exercise (1)
------------------------------------------------------------------------
Balance at March 31, 2006 $ 246
------------------------------------------------------------------------


5. Cash payments

The following cash payments were made (received):

------------------------------------------------------------------------
------------------------------------------------------------------------
March 31, March 31,
2006 2005
------------------------------------------------------------------------
Interest paid $ 478 $ -
Interest received (9) (130)
Taxes paid 10 16


6. Related party transactions:

At March 31, 2006, accounts receivable include $90,000 due from companies controlled by a director of the Company and accounts payable include $44,000 due to a company controlled by a director of the Company. The director was previously a director of Aquest Energy (a company purchased by Anderson Energy in September 2005) and the amounts arise as a result of common joint venture interests held by the director and Aquest Energy. The transactions have been recorded under the same terms and conditions as transactions with unrelated parties.

In February, 2006, the Company issued 576,394 common shares at an average price of $7.74 per share as consideration for the purchase of five property acquisitions. Four of the transactions were producing property acquisitions where the Company acquired a partner minority interest in petroleum and natural gas assets in the former Aquest Energy properties. Two of the transactions were with companies controlled by a director of Anderson Energy, for a total consideration of 224,660 shares at an average purchase price of $7.81 per share or $1.8 million. The two transactions were completed under the same terms and conditions as the other transactions and were approved by the TSX prior to completion.



Corporate Information

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

Directors Officers

J.C. Anderson 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
R.T. (Tim) Swinton (1)(2)
Calgary, Alberta Daniel F. Kell
Vice President, Land

David M. Spyker
Vice President, Business Development

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


Auditors

KPMG LLP
Calgary, Alberta

Independent Engineers
AJM Petroleum Consultants

Legal Counsel
Bennett Jones LLP

Registrar & Transfer Agent
Valiant Trust Company

Stock Exchange
The Toronto Stock Exchange
Symbol AXL


Abbreviations used:

bbls - barrels
bpd - barrels per day
Mbbls - thousand barrels
BOE - barrels of oil equivalent
BOED - barrels of oil equivalent per day
MBOE - thousand barrels of oil equivalent
MMBOE - millions of barrels of oil equivalent
Mcf - thousand cubic feet
Mcfd - thousand cubic feet per day
Mcfe - thousand cubic feet equivalent
MMcf - million cubic feet
MMcfd - million cubic feet per day
GJ - gigajoule



Contact Information

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