Shellbridge Oil & Gas, Inc.
TSX : SHB

Shellbridge Oil & Gas, Inc.

May 15, 2006 08:00 ET

Shellbridge Oil & Gas, Inc.: Highlights of Results-First Quarter Interim, Fiscal 2006

RICHMOND, BRITISH COLUMBIA--(CCNMatthews - May 15, 2006) - SHELLBRIDGE OIL & GAS, INC. (TSX:SHB) is pleased to report financial and operational highlights for the first quarter ended March 31, 2006.

We commenced operations on October 1, 2005, after certain assets of Dynamic Oil & Gas, Inc. were transferred to us upon the completion of a Plan of Arrangement. Therefore there are no comparative figures available.

The reader of this report should be aware that historical performance results are not necessarily indicative of future performance. Additional information relating to these interim results can be found at www.sedar.com.



Summary of Operational Highlights
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For the Three Months
($ 000's unless otherwise stated) Ended Mar 31, 2006
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Gross revenues 4,780
Cash flow used in operating activities (67)
Net loss (963)
Net loss per share, basic and diluted ($/share) (0.03)
Daily average production (boe/d) 1,792
Total production (mboe) 161
Capital investment program (includes exploration
expenses and capital assets)(1) 4,113
Total assets 31,935
Working capital(2) 593
Working capital ratio(3) 1.0:1
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(1) Seismic and unsuccessful drilling costs comprise the majority of
our exploration expenses as reported in our Statement 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 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.


During the three month period, our weighted average price realized from the sale of our heavy crude oil was $27.48 per barrel and from natural gas was $7.18 per mcf.

Total production for the period was 161 mboe and total daily average production was 1,792 boe per day, approximately 67% over the previous quarter ended December 31, 2005. The increase in production was mainly the result of the start-up at Mantario East of three wells - two were heavy crude oil wells and the other was our first natural gas well. Production was also up due to five wells that started production late in the previous quarter at Mantario East. Our overall production mix for the three months was 92% heavy crude and 8% natural gas. We expect that our Fiscal 2006 exit rate will be approximately 86% heavy crude oil and the balance sweet natural gas.

During the three month period we recognized one dry hole, acquired 2D seismic, and expensed certain site preparation costs for total exploration expenses of $0.8 million.

The following table summarizes the costs we incurred by classification on our capital investment program during the three month period ended March 31, 2006.



Capital Investment Program by Classification(1)
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For the Three Months
($000's) Ended Mar 31, 2006
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Land acquisitions -
Drilling, completions and equipping:
Exploratory(2) 382
Development 2,433
Facilities and pipelining 1,168
Seismic 107
Other 23
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Total 4,113
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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 that 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 March 31, 2006 exploratory well-drilling costs of $3.7
million remain capitalized on our balance sheet. These costs
relate to five wells. Various projects are planned in Fiscal 2006
to determine if proved reserves can be assigned to each of the
five wells. The wells are as follows: three heavy oil wells at
Mantario East and Flaxcombe, Saskatchewan; two natural gas wells
at Pica, Alberta and Rigel, British Columbia.


During the three-month period we incurred expenditures of $4.1 million on our capital investment program, 80% of which was spent at Mantario East and Flaxcombe in Saskatchewan, and 20% at Rigel, Cypress/Chowade, and Orion in British Columbia.

We financed our capital investment program through initial funding cash available at the beginning of the period.

During the three-month period, our capital investment program expenditures totaled $4.1 million, an amount that was allocated by property and classification as follows:



Capital Investment Program by Property and Classification
(Including Exploration Expense Related to Drilling and Seismic, and
Capital Assets)
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Drilling,
Completions Facilities
($ 000's) and Equipping and Pipelining Seismic Other Total
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British Columbia
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Cypress/Chowade 27 - - 7 34
Orion 1 - - (5) (4)
Rigel 704 - 89 - 793
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Total British
Columbia 732 - 89 2 823
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Saskatchewan
Mantario East 2,070 1,168 18 8 3,264
Flaxcombe/
Sandgren 12 - - 5 17
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Total
Saskatchewan 2,082 1,168 18 13 3,281
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Pica, Alberta 1 - - - 1
Other - - - 8 8
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Total 2,815 1,168 107 23 4,113
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We drilled four wells at a total cost of $2.8 million. One well, targeting natural gas at Rigel at a working interest of 50%, was unsuccessful. We also drilled three wells targeting heavy crude oil at Mantario East, each at a working interest of 75%. The three wells targeting heavy crude oil were completed at period end, two as producing wells and the other one as a standing well awaiting tie-in.

Expenditures incurred on facilities and pipelining during the three-month period totaled $1.2 million. These expenditures were incurred mainly on the construction of our natural gas processing facility at Mantario East.

During the three month period we invested $0.1 million on seismic data activity, most of which was for a 14.9 kilometer, 2D seismic shoot at Rigel.

Financial Results

The growth in our daily average production rate for the three-month period ended March 31, 2006 was the primary reason why revenues increased to $4.8 million, an increase of 34% over the previous quarter ended December 31, 2005. With expected stronger prices and a 2,000 boe/d production target, revenue should continue to strengthen during the balance of Fiscal 2006.

The following table shows a breakdown of our revenue by commodity during the three month period ended March 31, 2006.



Revenue by Commodity
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Three Months Ended
($ 000's) Mar 31, 2006
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Heavy crude oil 4,264
Natural gas 511
Light/medium crude oil 5
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Total 4,780
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The following table shows our daily average production rates and total production by commodity and field, for the three-month period ended March 31, 2006.



Daily Average Production Rates by Commodity and Field,
and Total Production
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Three Months Ended
(Units as stated) Mar 31, 2006
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Daily average production rates
Natural gas (mcf/d)
Cypress/Chowade, British Columbia 768
Mantario East, Saskatchewan 54
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Total natural gas (mcf/d) 822
Total natural gas (boe/d 6:1) 137
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Light/medium crude oil (bbl/d)
Elmore and Rapdan, Saskatchewan 1
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Total light/medium crude oil (bbl/d) 1
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Heavy crude oil (bbl/d)
Mantario East, Saskatchewan 1,654
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Total heavy crude oil (bbl/d) 1,654
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Total daily average production (boe/d) 1,792
Total production all products (mboe) 161
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The following table shows our weighted average prices realized by commodity for the three month period ended March 31, 2006.



Weighted Average Commodity Prices
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Three Months Ended
(Units as stated) Mar 31, 2006
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Heavy crude oil ($/bbl) 27.48
Natural gas ($/mcf) 7.18
Light/medium crude oil ($/bbl) 51.53
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Royalties for the three-month period ended March 31, 2006 were $1.2 million or $7.63 per boe, a decrease in unit royalties of 15% from the quarter ended December 31, 2005. Most of this unit decrease was the result of production from horizontal crude oil wells at Mantario East that were eligible for a crown royalty holiday. Of our total royalties, 44% were crown burdens and 56% were freehold and gross overriding burdens. In the balance of Fiscal 2006, we expect our unit royalty rate to be approximately $8.00 per boe.

Production and transportation costs for the three-month period ended March 31, 2006 totaled $1.3 million or $7.83 per boe, a decrease of 23% from the quarter ended December 31, 2005. This decrease reflects improved processing efficiencies created through the recent start-up of a new battery facility at Mantario East. We currently operate approximately 95% of our production, allowing us to better control production and transportation costs.

Amortization and depletion expense for the three-month period ended March 31, 2006 was $1.7 million or $10.81 per boe, a decrease of 12% from the quarter ended December 31, 2005. This decrease was mainly due to a higher production volume denominator for calculating the per boe costs applied against a numerator partially comprised of non-producing capital costs.

The following table shows our exploration expenses and unit exploration expenses by expense category for the three-month period ended March 31, 2006.



Exploration Expenses and Unit Exploration Expenses
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Three Months Ended
($ 000's unless otherwise stated) Mar 31, 2006
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Drilling(1) 693
Seismic data activity 107
Other 15
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Total exploration expenses 815
Unit exploration expenses per boe ($) 5.05
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(1) Exploration drilling costs are capitalized pending evaluation as
to whether sufficient quantities of reserves have been found to
justify commercial production. If commercial quantities of
reserves are not found, costs of exploration drilling costs are
expenses. All exploratory wells are evaluated for commercial
viability within twelve months of the completion. Exploration
wells that discover potentially commercial quantities of reserves
in areas requiring major expenditures before the commencement of
production and where commercial viability requires the drilling
of additional exploratory wells remain capitalized as long as the
drilling of the additional wells is underway or firmly planned.


During the three-month period ended March 31, 2006, we expensed the costs of drilling one well at Rigel, British Columbia. This was due to the unsuccessful drilling of an exploration well targeting natural gas at 50% working interest for $0.4 million. The balance of the exploratory drilling costs related mostly to one unsuccessful drilling attempt at Mantario East recognized during the period ended December 31, 2005.

Total general and administrative expenses during the three-month period ended March 31, 2006 were $0.7 million or $3.77 per boe, a decrease in unit G&A of 58% from the quarter ended December 31, 2005. This unit decrease resulted mainly from increased production levels and due to the accrual in the quarter ended December 31, 2005 of certain costs that would normally be incurred over a full year.

Subsequent Event

Under joint announcement with True Energy Trust of Calgary, Alberta ("True") on April 11, 2006, the Company entered into an agreement with True and True Energy Inc. ("True Energy"), a wholly-owned subsidiary of True, whereby, subject to certain conditions, True Energy will acquire all of our issued and outstanding Common Shares on the basis of 0.14 trust units of True for each outstanding share of Common Stock of ours. The contemplated transactions have received unanimous support of both our and True's board of directors. For further details, see our first quarter, fiscal 2006 interim report and other filings on our corporate website, www.shellbridge.ca or at www.sedar.com.

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 assumptions 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 registration statement on form 20-f and other continuous disclosure filings.


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