Shellbridge Oil & Gas, Inc.
TSX : SHB

Shellbridge Oil & Gas, Inc.

March 30, 2006 09:00 ET

Shellbridge Oil & Gas, Inc.: Financial Results for Stub-Year Fiscal 2005

RICHMOND, BRITISH COLUMBIA--(CCNMatthews - March 30, 2006) - SHELLBRIDGE OIL & GAS, INC. ("Shellbridge") (TSX:SHB) announced today that we have filed with regulators our financial statements that reflect our financial position as at December 31, 2005 and our results of operations and cash flows since the commencement of operations on October 1, 2005. Because of the summary nature of this news release, readers should access our Fiscal 2005 Annual Report and our Annual Information Form at our corporate website: www.shellbridge.ca or at the regulatory filings website: www.sedar.com.

We commenced operations on October 1, 2005, when certain assets of Dynamic Oil & Gas, Inc. ("Dynamic") were transferred to us upon the completion of a Plan of Arrangement. Certain information of a financial nature relating to the assets transferred to us is reported in this news release, however, comparative financial statements relating to Shellbridge are not available.

Plan of Arrangement and Related Party Transaction - On September 30, 2005, we received our initial asset base under the terms of the Plan of Arrangement, which resulted in all our shareholders effectively receiving, among other consideration, one Shellbridge common share for each common share of Dynamic held. At the time of this transaction, we were a related company to Dynamic, resulting in a transfer to us from Dynamic, of certain net assets at their carrying values.

Pursuant to the Plan of Arrangement, we began operations with daily average production of approximately 900 barrels of oil equivalent per day (boe/d), 190,716 gross acres (92,515 net acres) and approximately $29.7 million in income tax pools available for deduction against future taxable income. Of our total acreage, approximately 90% was undeveloped, 71% of which was located in northeastern British Columbia.

In terms of our balance sheet and pursuant to the Plan of Arrangement, we were allocated the following net assets:



Net Assets Received
($000's unless otherwise stated) Amount
------------------------------------------------------------
Cash 3,564
Assumed working capital deficit (net of cash) (983)
Crude oil and natural gas interests 15,321
Capital assets 341
Asset retirement obligation (989)
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Common shares issued pursuant to the
Plan of Arrangement (25,754,278) 17,254
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Summary of Operational Highlights
------------------------------------------------------------
For the Three
Months Ended
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($ 000's unless otherwise stated) Dec. 31, 2005
Gross revenues 3,575
Cash flow from operating activities (2,124)
Net loss 1,868
Net loss per share ($/share), basic and diluted 0.06
Daily average production (boe/d) 1,070
Total production (mboe) 98
Capital investment program (includes
exploration expenses and capital assets) (1) 4,295
Total assets 32,967
Working capital (2) 3,787
Working capital ratio (3) 1.3:1
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(1) Seismic and unsuccessful drilling costs comprise the majority of
our exploration expenses as reported in our Statements of
Operations and Deficit. Capital expenditures are reported on our
Balance Sheets. When combined, annual expenditures for capital,
and annual expenses for seismic and unsuccessful drilling
represent the sum total of our fiscal capital investment program.

(2) Working capital is defined as current assets less current
liabilities.

(3) We have no long-term debt. Working capital ratio is defined as
current assets divided by current liabilities.


Total production for the three months of operations was 98 mboe and total daily average production was 1,070 boe per day, approximately 19% over initial operations on October 1, 2005. The increase in production was mainly the result of the start-up of five heavy crude oil wells at Mantario East, a field that contributed 72% of our gross revenues and 86% of our daily average production rate for the three month period ended December 31, 2005.

Our daily exit production rate for 2005 was approximately 1,550 boe/d. Our overall production mix for the three months of operations was 86% heavy crude oil from the Mantario East field in southwestern Saskatchewan and 14% natural gas from the Cypress/Chowade property in northeastern British Columbia. We anticipate our exit production will reach 2,000 boe/d for Fiscal 2006, subject to rig availability, drilling successes and the timing of completions and tie-ins.

During the three months of operations ended December 31, 2005, our weighted average price realized from the sale of our natural gas was $11.92 per mcf and from heavy crude oil was $30.33 per barrel.

Production and transportation costs for the three month period ended December 31, 2005 totalled $1.0 million or $10.22 per boe. Our corporate average production cost for Fiscal 2006 is expected to range from $7 - $8 per boe, an expected decrease that is mainly due to anticipated, improved processing efficiencies created through the recent start-up of a new battery facility at Mantario East.

Amortization & depletion expense (A&D) for the three month period contributed $1.4 million or $14.33 per boe of non-cash expense to our net loss. Included in this amount are certain asset retirement obligation adjustments of $0.2 million. After removing the impact of the adjustments, our unit A&D expense was $12.21 per boe. It is anticipated that our Fiscal 2006 A&D rate per boe will rise as increases in the current cost environment exceed historical costs.
Our general and administrative expenses (G&A) of $0.9 million or $8.91 per boe for the three month period, included $0.2 million relating to an accrual for professional fees and printing costs of our annual report and information circular. These and other such costs are normally absorbed over a full production year. Our G&A costs for Fiscal 2006 are expected to be between $3 and $4 per boe. The projected decrease in unit cost is a result of an anticipated growth in annual production levels and our first, full-year normalization of costs.

During the three month period ended December 31, 2005, we recognized two dry holes, acquired 3D and 2D seismic and expensed certain site-preparation costs, all of which contributed $1.5 million of exploration expenses toward our net loss. One of the dry holes had commenced drilling prior to October 1, 2005.

The following table summarizes by classification, the costs we incurred on our capital investment program during the three month period ended December 31, 2005.



Capital Investment Program (1)
------------------------------------------------------------
For the Three
Months Ended
($000's) Dec. 31, 2005
------------------------------------------------------------
Land acquisitions 241
Drilling, completions and equipping
- exploratory (2) 734
- development 1,999
Facilities and pipelining 630
Seismic 511
Other 180
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Total 4,295
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(1) We follow the successful efforts method of accounting, whereby
costs of drilling an unsuccessful well are recorded as
exploration expense when it becomes known the well did not result
in a discovery of proved reserves or where one year has elapsed
since the completion of drilling and near-term efforts to
establish proved reserves are not foreseeable, intended, or in
our control.

(2) As at December 31, 2005 exploratory well-drilling costs of $3.1
million remain capitalized on our balance sheet. These costs
relate to six wells. Various projects are planned in Fiscal 2006
to determine if proved reserves can be assigned to each of the
six wells. The wells are as follows: four heavy oil wells at
Mantario East and Flaxcombe, Saskatchewan; two natural gas wells
Pica, Alberta and Rigel, British Columbia.


During the three month period, we advanced our corporate strategies through the spending of $4.3 million on our capital investment program, 71% of which was spent at Mantario East and Flaxcombe in Saskatchewan, 26% at Rigel and Orion in British Columbia and 3% at Pica, Alberta and other locations.

We financed our capital investment program through initial funding cash of $1.2 million pursuant to the Plan of Arrangement, cash flow from operating activities and the completion of a private placement resulting in cash proceeds, net of fees and financing costs, of approximately $3.9 million. Upon closing of the private placement, we issued at $1.20 per share, 1,666,666 flow-through common shares and 1,666,667 common shares (non-flow-through).

The gross proceeds of the flow-through portion of the private placement were $2.0 million, all of which must be spent by December 31, 2006 on qualifying expenses for exploration-only activities that are specifically defined in the Income Tax Act (Canada). As at December 31, 2005, we had incurred approximately 53% of the required obligation. On January 19, 2006, we officially renounced the tax benefits of the entire $2.0 million in favour of the flow-through shareholders.

During the three month period ended December 31, 2005, we did not record any current income tax expense, however, we recorded a future income tax recovery of $0.8 million.

Effective December 31, 2005, our total proved reserves on a before-royalties, constant-price basis were independently estimated at 1,343 mboe. They were comprised of five mboe of light/medium crude oil, 1,071 mboe of heavy crude oil, 261 mboe of natural gas and six mboe of natural gas liquids.

Our planned strategy for Fiscal 2006 is to continue to explore and develop our Mantario East property and to enhance production at Cypress/Chowade. We have budgeted to invest approximately $9.0 million toward our capital investment program. Approximately 85% of the budget is directed at lower-risk, development-type projects, with the balance aimed at exploration activity.

Our year-end working capital ratio was 1.3:1, which included certain disputed items recorded in our accounts payable and accrued liabilities in favour of one of our joint venture partners. While we believe that the amount we have recorded is sufficient to provide for its eventual resolve, the ultimate settlement of the obligation could result in a material adjustment.

On March 17, 2006, we established a revolving, demand credit facility with our bank for an amount of $6.5 million. Outstanding balances bear interest at prime plus 1/2% and unused availability is levied a fee of 0.125%. The facility is collateralized by a $20 million floating debenture covering all our assets. Based on our production targets, our forecasts of strong commodity prices, and support from our bank loan facility, we expect to have adequate resources to meet our Fiscal 2006 requirements.

Shellbridge Oil & Gas, Inc. is a Canadian based oil and gas production and exploration company. The Company has a large land position comprised of 200,717 gross acres (99,697 net acres) and owns working interests in development and early-stage exploration properties in southwestern Saskatchewan, northwestern Alberta and northeastern and southwestern British Columbia.

On Behalf of the Board of Directors,

Wayne J. Babcock, President & CEO

Forward-looking statements - the above disclosure may contain statements that are forward-looking in nature. Forward-looking statements include all passages containing verbs such as aims, anticipates, believes, estimates, expects, hopes, intends, plans, predicts, projects or targets' or nouns corresponding to such verbs. Forward-looking statements in this news release include, without limitation, uncertainty about achievable and sustainable production rates, timing of drilling completions and tie-ins, available financing, success in the discovery of proved reserves and future product mix, attainment of various unit cost factors, and the settlement of certain disputed payables within expectations. Forward-looking statements are necessarily based upon a number of estimates and assumption that, while considered reasonable by management, are inherently subject to known and unknown risks and uncertainties and other factors referenced in the corporation's annual information form and other continuous disclosure filings.


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