Cruiser Oil & Gas Ltd.
TSX VENTURE : COG

Cruiser Oil & Gas Ltd.

April 30, 2007 21:01 ET

Cruiser Announces Results for Year Ended December 31, 2006

CALGARY, ALBERTA--(CCNMatthews - April 30, 2007) - Cruiser Oil & Gas Ltd. (TSX VENTURE:COG) ("Cruiser" or the "Company") is pleased to announce its financial and operating results for the year ended December 31, 2006 with comparatives for 2005 and 2004.



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Three months ended
December 31
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2006 2005 2004
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FINANCIAL HIGHLIGHTS ($)
Petroleum and natural gas sales 331,210 199,621 -
Funds from (used in) operations (65,743) (36,789) (86,321)
Income (loss) for the period (244,728) (293,680) 77,159
Total assets
Net capital expenditures 1,645,104 3,321,679 17,643

OPERATIONAL HIGHLIGHTS ($)
Daily production - boe/d (6:1) 84 34 -
Price - $/boe 43.08 63.89 -
Operating Netback - $/boe 26.00 50.84 -
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Years ended
December 31
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2006 2005 2004
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FINANCIAL HIGHLIGHTS ($)
Petroleum and natural gas sales 1,037,048 720,011 -
Funds from (used in) operations (2,212) (120,007) 32,498
Income (loss) for the period (398,863) (721,815) 335,823
Total assets 18,700,768 14,667,054 3,419,778
Net capital expenditures 5,830,642 6,161,898 21,913

OPERATIONAL HIGHLIGHTS ($)
Daily production - boe/d (6:1) 63 40 -
Price - $/boe 44.80 48.86 -
Operating Netback - $/boe 28.34 34.42 -
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REPORT TO SHAREHOLDERS

Cruiser is pleased to report the continued progress made during 2006 in the rebuilding and revitalization of the Company.

OPERATIONS HIGHLIGHTS

- Increased average production by 58% to an average of 63 boe/day for the year ended December 31, 2006

- Increased average year end quarter production by 147% to 84 boe/day in 2006

- Increased petroleum and natural gas sales by 44% to $1,037,048 for the year ended December 31, 2006

- Increased undeveloped land position to 1,920 gross acres (864 net) in 2006 through land acquisitions and earning

- Raised $5.0 million of net equity financing during the year ended December 31, 2006

- Participated in nine drilling and/or recompletion operations of which eight were successful and one is still being evaluated

OUTLOOK FOR 2007

The Company's current working interest production is estimated to be 100 boe/day with an estimated additional 100 boe/day waiting to be optimized.

At Swan Hills, the 15-26 well has been successfully reactivated and is now on production. The Company is currently in the process of installing a high volume lift pump to further increase production.

At Willesden Green, the 6-35 well has been put on production and is currently producing at reduced rates, pending a review of the flowing conditions of the well, associated facilities and gathering system. The 9-34 well has been drilled to depth and the status remains confidential.

At Kakwa, the 13-1 Swan Hills well has been drilled to total depth. The well was acidized during the first week of March 2007, however, testing operations were not completed due to wildlife constraints which required all of the equipment to be removed from the lease prior to March 15, 2007. As a result, the well has been suspended pending further evaluation of the pressure data. Cruiser has a 15% WI in this well.

Cruiser is evaluating additional prospects for the continued growth of the Company.

BOEs are derived by converting gas to oil in the ratio of six thousand cubic feet of gas to one barrel of oil (6 Mcf: 1 bbl). 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.

Douglas L. Meiklejohn, President & Chief Executive Officer

MANAGEMENT'S DISCUSSION AND ANALYSIS

This MD&A is dated as of April 24, 2007

This Management's Discussion and Analysis ("MD&A") of financial results and related data is reported in Canadian dollars and has been prepared in accordance with Canadian generally accepted accounting principles ("GAAP"), and should be read in conjunction with the financial statements for the years ended December 31, 2006 and 2005.

Information contained herein includes estimates and assumptions which management is required to make concerning future events, and may constitute forward-looking statements under applicable securities laws. Forward-looking statements include plans, expectations, estimates, forecasts and other comments that are not statements of fact. Although Cruiser Oil & Gas Ltd. ("Cruiser" or "the Company") views such expectations as reasonable, no assurance can be given that such expectations will be realized. Such forward-looking statements are subject to risks and uncertainties and may be based on assumptions that may cause actual results to differ materially from those implied herein, and therefore are expressly qualified in their entirety by this cautionary statement.

This MD&A presents and discusses results on a BOE (barrels of oil or equivalent) basis. This presentation may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 mcf: 1 bbl (barrel) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All BOE conversions in this report are derived by converting natural gas to oil in the ratio of nine thousand cubic feet of natural gas to one barrel of oil.

Cruiser Oil & Gas Ltd. changed its name from Hoodoo Hydrocarbons Ltd. in July 2005. Cruiser re-commenced trading on the TSX Venture Exchange on July 28, 2005.

FOURTH QUARTER 2006 RESULTS

During the fourth quarter, the Company focused on the completion of the Willesden Green 06-35 well, the Swan Hills 15-26 workover and reactivation, and was able to continue drilling on the Kakwa 13-01 well.

Production for the fourth quarter of 2006 averaged 84 boe/day as compared to 34 boe/day in the comparative fourth quarter of 2005. The increase in the comparative 2006 and 2005 periods is from Blackstone, Ansell and Herronton wells. The average price for oil and natural gas liquids was $53.37 per barrel and the average price for gas was $6.54 per mcf during the fourth quarter of 2006. This compares to the average commodity prices for the fourth quarter of 2005 of $54.30 per barrel and $11.79 per mcf. The average royalty rate for the comparative quarters was both 11%. Operating costs were $93,905 ($12.21 per boe), compared to $18,046 ($5.78 per boe), in the comparative quarter in 2005.

General and administrative expenses for the fourth quarter of 2006 were $275,049 as compared to $245,480 in the same period in 2005.

Interest expense decreased in the fourth quarter to $761 as compared to $6,266 in the same quarter of 2005. The interest expense for 2006 relates mainly to the unspent flow-through expenditures until the eligible expenditures were incurred. For the comparative 2005 period, the flow-through proceeds were not raised until the third quarter of 2005 and the majority of the debt was paid during the earlier portion of 2005.

Depletion, depreciation and accretion for the fourth quarter of 2006 was $286,884 ($37.31 per boe) as compared to the fourth quarter of 2005 of $86,838 ($27.79 per boe). The increased amount is a result of the increased production in 2006 plus the increased cost of capital expenditures.

The loss for the fourth quarter of 2006 was $244,728 as compared to a loss of $293,680 during the same period in 2005.



FINANCIAL HIGHLIGHTS
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Three months ended Years ended
December 31 December 31
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$ 2006 2005 2006 2005
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Petroleum and natural gas
sales 331,210 199,621 1,037,048 720,011
Funds used in operations (65,743) (36,789) (2,212) (120,007)
Loss for the period (244,728) (293,680) (398,863) (721,815)
Net capital expenditures 1,645,104 3,321,679 5,830,642 6,161,898
Weighted average shares
outstanding - basic 85,943,252 80,589,862 82,185,785 43,932,739
Common shares outstanding
- end of period 121,891,052 80,589,862 121,891,052 80,589,862
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SUMMARY OF QUARTERLY RESULTS

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2006
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December September June March
$ 31 30 30 31
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Net petroleum and natural
gas revenue 331,210 234,304 270,529 201,005
Net income (loss) (244,728) (131,456) 95,410 (118,089)
Net income (loss) per
share (0.00) (0.00) 0.00 (0.00)
Net capital expenditures 1,645,104 1,278,022 442,443 2,465,073

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2005
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December September June March
$ 31 30 30 31
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Net petroleum and natural
gas revenue 199,621 196,902 151,111 172,377
Net income (loss) (293,680) (269,914) (157,345) (876)
Net income (loss) per share (0.00) (0.00) (0.01) (0.00)
Net capital expenditures 3,321,679 2,315,803 532,276 (7,960)
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YEARS ENDED DECEMBER 31 RESULTS

PETROLEUM AND NATURAL GAS SALES

Oil and natural gas revenues increased to $1,037,048 for the year ended December 31, 2006 as compared to $720,011 for the 2005 year. For the year ended December 31, 2006, prices for the Company's production averaged $57.89 per barrel of oil and liquids and $6.55 per mcf of natural gas, as compared to $56.10 per barrel of oil and liquids and $7.80 per mcf of natural gas for the 2005 year. The increased 2006 revenues were primarily a result of increased production offset by decreased gas prices.



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Three months ended Years ended
December 31 December 31
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2006 2005 2006 2005
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Petroleum and natural gas
sales ($) 331,210 199,621 1,037,048 720,011
$/BOE 43.08 63.89 44.80 48.86
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PRODUCTION

For the year ended December 31, 2006, production of natural gas averaged 268 mcf/day and oil and NGL averaged 18 bbls/day for a total of 63 boe/day, as compared to an average of 152 mcf/day of natural gas and 15 bbls/day of oil and NGL for a total of 40 boe/day for the same period in 2005.



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Three months ended Years ended
December 31 December 31
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2006 2005 2006 2005
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Natural gas (mcf/d) 365 119 268 152
Crude oil and NGLs (bbls/d) 23 14 18 15
Total (boe/d) 84 34 63 40
Percentage natural gas (%) 73 59 71 63
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ROYALTIES

The royalties for the comparative periods are virtually the same on both a percentage and boe basis.



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Three months ended Years ended
December 31 December 31
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2006 2005 2006 2005
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Net royalties ($) 37,405 22,711 113,080 72,308
Net royalties as a % of revenue 11 11 11 10
$/BOE 4.86 7.27 4.88 4.91
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OPERATING EXPENSES

During the year ended December 31, 2006, the Company incurred operating expenses of $267,763 as compared to $140,558 for the same period in 2005. The operating expenses have increased on a boe basis from the prior year due to increased cost of services plus production from higher operating cost areas.



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Three months ended Years ended
December 31 December 31
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2006 2005 2006 2005
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Operating expenses ($) 93,905 18,046 267,763 140,558
$/BOE 12.21 5.78 11.57 9.54
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GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative expenses increased to $703,048 for the year ended December 31, 2006 from $577,499 for the comparative period in 2005. The dollar increase was a result of Cruiser's increased capital program and related revenues, however the costs reduced to $30.37 per boe as compared to $39.19 per boe in the 2005 comparative year.



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Three months ended Years ended
December 31 December 31
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2006 2005 2006 2005
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General and administrative expense
($) 275,049 245,480 703,048 577,499
$/BOE 35.77 78.57 30.37 39.19
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INTEREST INCOME AND EXPENSE

Interest expense for the year ended December 31, 2006 decreased to $54,303 from $141,147 for the comparative period in 2005. At the end of 2004, the Company had loan obligations of $1.2 million, all of which was paid out during 2005. In addition, equity issues during 2005 increased the cash balances and interest was earned on these balances. The majority of the interest expense for 2006 relates to the interest accrued on the unspent flow-through expenditures. This interest accrues on a monthly basis and was paid at the end of February 2007.



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Three months ended Years ended
December 31 December 31
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2006 2005 2006 2005
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Interest expense ($) 761 6,266 54,303 141,147
Interest income ($) 10,167 48,346 84,351 68,156
Net interest expense (income)
($/BOE) (1.22) (13.47) (1.30) 4.95
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DEPLETION AND DEPRECIATION

Depletion and depreciation for the year ended December 31, 2006 was $727,241 compared to $264,609 for the same period in 2005.



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Three months ended Years ended
December 31 December 31
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2006 2005 2006 2005
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Depletion and depreciation ($) 282,081 83,716 727,241 264,609
$/BOE 36.69 26.79 31.41 17.96
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ASSET RETIREMENT OBLIGATIONS

The obligation at the end of December 31, 2006 is estimated to be $230,072 based on the total undiscounted obligation of $651,650 adjusted for a discount rate of 8% and inflation of 2% over an average reserve life of 14 years. Accretion of $15,104 for the year ended December 31, 2006 ($11,522 for the same period of 2005) was recorded.



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Three months ended Years ended
December 31 December 31
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2006 2005 2006 2005
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Accretion expense ($) 4,803 3,122 15,104 11,522
$/BOE 0.62 1.00 0.65 0.78
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FUNDS FROM OPERATIONS

For the year ended December 31, 2006, the funds used in operations were $2,212 as compared to the 2005 funds used in operations of $120,007.



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Three months ended Years ended
December 31 December 31
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2006 2005 2006 2005
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Funds used in operations ($) (65,743) (36,789) (2,212) (120,007)
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Funds from operations is a non-GAAP measure that represents funds generated from operating activities before changes in non-cash working capital. This is considered a key measure as it demonstrates the Company's ability to generate the funds necessary to fund future growth through capital investment. Funds from operations may not be comparable to similar measures used by other companies.

NET LOSS

The net loss for the year ended December 31, 2006 was $398,863 compared to a net loss of $721,815 over the same period in 2005. The decrease in net loss was due the adjustment to future tax recoveries as a result of a reduction in the corporate income tax rate.



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Three months ended Years ended
December 31 December 31
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2006 2005 2006 2005
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Net loss ($) (244,782) (293,680) (398,863) (721,815)
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CAPITAL EXPENDITURES

During the year ended December 31, 2006, the Company incurred $5,830,642 in net capital expenditures as compared to $6,161,898 over the same period in 2005. The Company participated in four operations under the Master Participation Agreement between the Company and a joint venture partner. In addition, the workover of the Swan Hills 15-26 well, the drilling and completion of the Willesden Green 06-35 well and continued drilling and completion of the Kakwa well all commenced during 2006.



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Three months ended Years ended
December 31 December 31
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2006 2005 2006 2005
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Capital expenditures, net ($) 1,645,104 3,321,679 5,830,642 6,161,898
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LIQUIDITY AND CAPITAL RESOURCES

The Company commenced the 2006 year with a working capital of $4,547,901. The net oil and gas revenue plus net interest income was almost sufficient to cover the general and administrative costs incurred during the year. The 2006 capital expenditures in the amount of $5,830,642 were financed from the opening working capital plus additional equity issues from stock option exercises and private placements.

The Cavendish Debenture was settled on August 1, 2006 for a total cash payment of $300,000 which was comprised of the principal amount of $250,000 and accrued interest of $50,000.

The flow-through expenditure commitments of $7.0 million from the August 2005 issue were completed by December 31, 2006. In December 2006, pursuant to a private placement, the Company raised gross proceeds of $4,964,000 of which $1,000,000 was on a flow-through basis. The qualifying expenditures for this flow-through must be incurred by December 31, 2007.

As at December 31, 2006, the Company's working capital had been reduced to $3,963,431. These funds will be utilized to satisfy the flow-through commitment and fund the anticipated capital expenditures for 2007.

The Company has no off-balance sheet arrangements.

Financial instruments consist of those shown on the Balance Sheet.

SHARE CAPITAL

On August 24, 2005, pursuant to the private placement, 20,000,000 flow-through shares were issued. The Company had expended the $7,000,000 of flow-through proceeds on qualifying expenditures by December 31, 2006.

At the beginning of 2006, the Company had 80,589,862 issued and outstanding shares. During the year ended December 31, 2006, 1,125,000 shares were issued upon the exercise of the same number of options for gross proceeds of $112,500. In December 2006, pursuant to a private placement, 40,176,190 shares were issued for gross proceeds of $4,964,000. Included in this private placement were proceeds of $1,000,000 on a flow-through basis of which the qualifying expenditures must be incurred by December 31, 2007. As at December 31, 2006, the total issued and outstanding common shares were 121,891,052. Subsequent to the year end, 166,666 options have been exercised for an equivalent number of shares and gross proceeds of $16,667 resulting in 122,057,718 shares outstanding as of the date of this MD&A.

Options

At the beginning of 2006 there were 6,645,000 options outstanding. During 2006, a total of 1,125,000 options were exercised and 1,025,000 options were cancelled. This reduces the total options outstanding as at December 31, 2006 to 4,495,000 outstanding. Subsequent to December 31, 2006, 166,666 options were exercised resulting in a total of 4,328,334 options outstanding as of the date of this MD&A.

Warrants

There were 400,000 warrants, exercisable at $0.30, outstanding at the commencement of 2006. These warrants expired, unexercised on September 8, 2006. There are no additional warrants outstanding.

RELATED PARTY TRANSACTIONS

The Company had the following related party transactions:

1. During 2006, the Company was charged $235,000 (2005 - $180,000) in management fees by officers and directors of the Company.

2. A law firm in which an officer of the Company is a principal charged the Company $40,479 (2005 -$128,099) for legal services. Accounts payable as at December 31, 2006 includes $42,683 (2005 - $nil) due to the law firm.

3. During 2006, the Company was charged $76,268 (2005 - $40,523) for administrative fees by a corporation controlled by an officer of the Company. At December 31, 2006, accounts payable includes an amount of $2,166 (2005 - $10,688).

All related party transactions are in the normal course of operations and have been measured at the exchange amount that is the amount of consideration established and agreed to by the related parties under terms similar to those negotiated with third parties.

OUTLOOK FOR 2007

The Company's current working interest production is estimated to be 100 boe/day with an estimated additional 100 boe/day waiting to be optimized.

At Swan Hills, the 15-26 well has been successfully reactivated and is now on production. The Company is currently in the process of installing a high volume lift pump to further increase production.

At Willesden Green, the 6-35 well has been put on production and is currently producing at reduced rates, pending a review of the flowing conditions of the well, associated facilities and gathering system. The 9-34 well has been drilled to depth and the status remains confidential.

At Kakwa, the 13-1 Swan Hills well has been drilled to total depth. The well was acidized during the first week of March 2007, however, testing operations were not completed due to wildlife constraints which required all of the equipment to be removed from the lease prior to March 15, 2007. As a result, the well has been suspended pending further evaluation of the pressure data. Cruiser has a 15% WI in this well.

Cruiser is evaluating additional prospects for the continued growth of the Company.

BUSINESS RISKS AND UNCERTAINTIES

The Company is exposed to several operational risks inherent in exploring, developing, producing and marketing crude oil and natural gas. These inherent risks include: economic risk of finding and producing reserves at a reasonable cost; financial risk of marketing reserves at an acceptable price given current market conditions; cost of capital risk associated with securing the needed capital to carry out the Company's operations; risk of environmental impact and credit risk of non-payment for sales contracts and joint venture partners.

The Company maintains a comprehensive insurance program to reduce risk to an acceptable level and to protect it against significant losses. The Company's risk in regards to financial instruments is detailed in note 17 to the December 31, 2006 audited financial statements.

Recent Developments

In September 2006, the Alberta government announced that the Alberta Royalty Tax Credit ("ARTC") program for corporations will be discontinued effective January 1, 2007. The ARTC program currently provides oil and natural gas producers a 25% credit against Alberta crown royalties, subject to certain restrictions.

Disclosure Controls and Procedures

Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the Company is accumulated and communicated to our management as appropriate to allow timely decisions regarding required disclosure. The Company's Chief Executive Officer and Chief Financial Officer have concluded, based on their evaluation as of December 31, 2006, that the Company's disclosure controls and procedures are effective to provide reasonable assurance that material information related to the Company, is made known to them by others within the entity. It should be noted that while the Company's Chief Executive Officer and Chief Financial Officer believe that our disclosure controls and procedures provide a reasonable level of assurance and that they are effective, they do not expect that the disclosure controls and procedures will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

Internal Controls over Financial Reporting

The Chief Executive Officer and Chief Financial Officer of the Company are responsible for designing internal controls over financial reporting or causing them to be designed under their supervision in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP. We have assessed the design of our internal control over financial reporting and during this process we have identified certain weaknesses in internal controls over financial reporting which are as follows:

- Due to the limited number of staff at the Company, it is not possible to achieve complete segregation of duties; and

- Due to the size of the Company and the limited number of staff, the Company does not have the technical accounting expertise and knowledge to address all complex and non-routine accounting transactions that may arise.

These weaknesses in the Company's internal controls over financial reporting result in a more than remote likelihood that a material misstatement would not be prevented or detected. Management and the board of directors work to mitigate the risk of material misstatement in financial reporting. In addition, when complex accounting and technical issues arise during preparation of the quarterly financial statements, outside consulting expertise is engaged. In spite of management's best efforts, there can be no assurance that this risk can be reduced to less than a remote likelihood of a material misstatement.

CRITICAL ACCOUNTING ESTIMATES

The Company's financial statements are prepared in accordance with Canadian generally accepted accounting principles. A comprehensive discussion of the Company's significant accounting policies is contained in Note 2 to the audited financial statements for the year ended December 31, 2006. The Company's significant accounting policies are subject to estimates and key judgments about future events, many of which are beyond management's control.

The Company believes the following are the most critical accounting estimates used in the determination of its financial results:

Petroleum and natural gas properties - depletion and ceiling test

The Company follows the full cost method of accounting by initially capitalizing all costs related to the acquisition, development and exploration of petroleum and natural gas reserves. Costs capitalized include land acquisition costs, geological and geophysical expenditures, rentals on undeveloped properties, costs of drilling productive and non-productive wells, together with overhead directly related to exploration and development activities and lease and well equipment. Costs capitalized are depleted using the unit-of-production method based on gross proved petroleum and natural gas reserves as determined by independent qualified reserve evaluators. Production and reserves of petroleum and natural gas are converted to common units of measure based on their relative energy content where one barrel of oil is equivalent to six thousand cubic feet of natural gas. The depletion base excludes the cost of significant unproved properties until it is determined whether proved reserves are attributable to the properties or impairment has occurred.

The Company performs a ceiling test whereby the carrying amount of property and equipment is compared to the sum of the undiscounted cash flows expected to result from the future production of proved and probable reserves and the cost, less any impairment of unproved properties. Estimated cash flows are discounted at the Company's credit-adjusted risk-free rate of interest using forecast prices and costs. The carrying amount of undeveloped properties and seismic excluded from the ceiling test are compared to independent evaluations of fair value and any excess carrying amount. Any impairments are recorded as additional depletion expense.

Estimates are the basis for amounts recorded as depletion and the ceiling test. These estimates include proved and probable reserves, production rates, future petroleum and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates could be material in future periods.

Asset retirement obligation

The Company recognizes the liability for the asset retirement obligation associated with the abandonment of petroleum and natural gas wells, related facilities, compressors and plants and the removal of equipment from leased acreage and returning such land to its original condition. The fair value of the Company's asset retirement obligation is recorded in the period a well or related asset is drilled, constructed or acquired. Fair value is estimated using the present value of the estimated future cash outflows to abandon the assets at the Company's credit-adjusted risk-free interest rate based on the expected timing of such cash outflows. Future costs and their expected timing are estimates that are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates could be material in future periods.

Income taxes

The Company records future tax assets and liabilities to account for the expected future tax consequences of events that have been recorded in its consolidated financial statements and its tax returns. These amounts are estimates and the actual tax consequences may differ from the estimates due to changing tax rates and regimes, as well as changing estimates of cash flows and capital expenditures in current and future periods. A valuation allowance is recorded to the extent that there is uncertainty regarding utilization of future tax assets.

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 and expense may differ from that estimated and recorded.

Stock-based compensation

Stock-based compensation expense is recorded in the statement of loss and deficit for all options granted based on the estimated fair value at the time of the grant and recognized as expense over the vesting period of the option. The fair value of options is estimated using the Black-Scholes pricing model based on estimates and assumptions for expected life of the options, expected volatility, risk-free interest rate and dividend yield. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates could be material in future periods.

CHANGE IN ACCOUNTING POLICIES

The Canadian Institute of Chartered Accountants ("CICA") has issued a number of accounting pronouncements which may impact the Company's reported results and financial position in future periods:

Comprehensive Income / Financial Instruments / Hedges

The CICA issued new standards in early 2005 for Comprehensive Income (CICA 1530), Financial Instruments - Recognition and Measurement (CICA 3855), Financial Instruments - Disclosure and Presentation (CICA 3861) and Hedges (CICA 3865), all of which are effective for fiscal periods beginning on or after January 1, 2007.

The standards require the inclusion of all financial instruments on a company's balance sheet at their fair value, other than held-to-maturity investments, loans and receivables. Held-to-maturity investments, loans and receivables would be measured at their amortized cost. The standards create a new statement of comprehensive income that will include changes in fair value of certain derivative financial instruments.

The Company elects to mark-to-market its derivative contracts under its risk management program. The accounting for hedging relationships for prior fiscal years is not retroactively changed. Therefore, management expects no restatement of prior periods as a result of these new standards.

International Financial Reporting Standards ("IFRS")

Over the next five years, the CICA will adopt its new strategic plan for the direction of accounting standards in Canada as ratified in 2006. As part of that plan, Canadian accounting standards for public companies will converge with IFRS. The Company will continue to monitor and assess the impact of the planned convergence of Canadian GAAP with IFRS.

ADDITIONAL INFORMATION

Additional information relating to the Company can also be found on SEDAR at www.sedar.com.

Contact Information