Dynamic Oil & Gas, Inc.: Highlights Of Results-First Quarter Interim, Fiscal 2003.

Energy Editors/Business Editors

RICHMOND, British Columbia--(BUSINESS WIRE)--June 2, 2003

DYNAMIC OIL & GAS, INC. is pleased to report financial and operational highlights for the first quarter ended March 31, 2003 ("2003-Q1"), compared with the three months ended March 31, 2002 ("2002-Q1").

Summary Highlights

In 2003-Q1 and compared to 2002-Q1, we:

-- Increased our gross revenue by 117% to $14.3 million - a

quarterly historical record;

-- Increased cash flow from operations(1) by 220% to $6.6 million

- our second-highest quarterly record;

-- Increased our daily average crude oil production volume by

491% to 756 barrels per day (bbls/d); and

-- Increased our net earnings by 296% to $3.3 million - a

quarterly historical record.

Also, during 2003-Q1 and compared to 2002-Q1, our:

-- Daily average production of natural gas and natural gas

liquids decreased by 26% or 947 barrels of oil equivalent per

day (boe/d);

-- Net debt to cash flow ratio on an annualized basis decreased

from 0.6:1 to 1.0:1.

At the close of 2003-Q1, we:

-- Achieved targeted spending levels of $6.2 million for capital

and exploration expense spending which represented 23% of our

$26.5 million total budget; and

-- Remained on track toward achieving our December 2003 estimated

daily average exit production rate of 5,200 boe per day, an

increase of 51% over our 2003-Q1 daily average production

rate.

Financial Highlights

(Units as stated)
For the three months ended March 31   2003-Q1  2002-Q1  Change  % Chg
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Net earnings (loss)                     3,322   (1,691)  5,013    296
Earnings per share ($/share)             0.16    (0.08)   0.24    300
Cash flow from operations(1)            6,592    2,058   4,537    220
Cash flow from operations
 per share ($/share)(1)                  0.32     0.10    0.22    220
Capital expenditures                    5,262    1,376   3,886    282
Net debt(2)                            16,189   13,281   2,908     22
Net debt to cash flow
 annualized (times)(3)                  0.6:1    1.0:1   0.4:1     40
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(1) Cash flow from operations is a non-GAAP measure that does not
    have standardized meaning as prescribed by GAAP and is therefore
    unlikely to be comparable to similar measures presented by other
    companies. We consider it a key measure as it demonstrates our
    ability to generate the cash flow necessary to fund future growth
    through capital investment and to repay debt.

($ 000's)                             2003-Q1  2002-Q1  Change  % Chg
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Cash provided by operating
 activities (GAAP)                      5,550    3,759   1,791     48
Changes in non-cash working capital
 affecting operating (GAAP)             1,042   (1,701)  2,743    161
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Cash flow from operations (non-GAAP)    6,592    2,058   4,537    220
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(2) Net debt is working capital, as we do not have any long-term
    debt.

(3) Net debt divided by cash flow from operations annualized.
    Annualized numbers are presented by applying the 2003-Q1 cash
    flow from operations number by four, however, this method does
    not reflect actual results for the nine-month extrapolated period
    and such results may differ from the result achieved by this
    calculation.

Operational Highlights

(Units as stated)
For the three months ended March 31  2003-Q1  2002-Q1  Change  % Chg
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Daily average production rates
  Natural gas (mcf/d)                 12,249   16,730  (4,481)   (27)
  Natural gas liquids (bbls/d)           639      840    (201)   (24)
  Crude oil (bbls/d)                     756      128     628    491
  All products (boe/d)(1)              3,437    3,756    (319)    (8)
Total production (mboe)(2)               309      338     (29)    (9)
Gas weighting (%)                         59       74     (15)   (20)
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(1) boe/d equals barrels of oil equivalent (6 mcf equals 1 bbl).

(2) mboe equals thousand barrels of oil equivalent.

Comparison of Significant Variances: 2003 - Q1 vs 2002-Q1

Capital Expenditures - in 2003-Q1 we invested $5.3 million, a 282% increase from the amount invested in 2002-Q1 as follows:

-- 10% in Alberta development properties to maintain and grow

existing production levels; and

-- 90% in British Columbia exploration properties for longer-term

production growth.

Our capital expenditures in 2003-Q1 were as follows:

-- $1.4 million on exploratory drilling, completions and

equipping costs, most of which was spent at St. Albert,

Alberta and Orion and Cypress/Chowade, British Columbia;

-- $1.1 million on development drilling and completions, most of

which was spent at St. Albert and Cypress/Chowade; and

-- $2.8 million on land acquisitions, 77% of which was spent at

Cypress/Chowade and the balance at Orion.

Our capital expenditures in 2002-Q1 were $1.4 million, most of which were as follows:

-- $1.5 million relating to the acquisition of additional working

interests at St. Albert;

-- $0.2 million on development completion costs at Orion; and

-- $(0.3) million, a net reduction due mainly to the recognition

in the period of unsuccessful drilling attempts at

Peavey/Morinville, Alberta.

Daily Average Production Rate - decreased by a net 319 boe/d or 8%, to 3,437 boe/d. Of this net decrease, natural gas decreased by 746 boe/d or 27%, to 2,042 boe/d (12,249 mcf/d), natural gas liquids decreased by 201 boe/d or 24%, to 639 boe/d, while crude oil increased by 628 boe/d or 491%, to 756 boe/d. Comprising the net decrease are the following:

-- An increase in crude oil by 628 boe/d due to three new oil

wells at St. Albert, one of which produced at a daily average

rate of 684 boe/d net to us;

-- A decrease in natural gas and natural gas liquids by 770 boe/d

due mainly to natural declines in reservoir pressures at St.

Albert, a factor that we plan to mitigate by phasing in

third-party compression through the latter half of the next

quarter;

-- A decrease in natural gas and natural gas liquids by 69 boe/d

due mainly to production declines at Halkirk, Alberta, a

factor we plan to offset during 2003 by drilling and tying-in

additional wells and adding third-party compression;

-- A decrease in natural gas by 108 boe/d at Peavey/Morinville,

Alberta due mainly to production declines.

Total Production - decreased by a net 29 mboe or 9%, to 309 mboe. This net decrease was due to the changes in our daily average production rates discussed above.

Weighted Average Commodity Prices - increased by the following amounts:

-- $4.67/mcf or 137%, to $8.09/mcf for natural gas due to cold

weather and supply concerns;

-- $16.32/bbl or 49%, to $49.58/bbl for crude oil due to strong

geo-political uncertainties and tighter supplies; and

-- $18.29/bbl or 122%, to $33.28/bbl for natural gas liquids due

to a combination of the reasons above.

Royalties, Mineral Taxes and Alberta Royalty Tax Credits (ARTC) - increased by an aggregate net $2.0 million or 124%, to $3.6 million. Unit royalties expense increased by $6.82 or 145%, to $11.53/boe due primarily to the following:

-- An increase of $1.68/boe due to royalty obligations associated

with production from our new 06-25 oil well at St. Albert. The

production at this well is burdened by a 40% royalty,

comprised of a 15% overriding and a 25% crown royalty, net of

ARTC; and

-- An increase of $5.14/boe due to higher commodity prices.

Production Costs - decreased by $0.6 million or 26%, to $1.6 million. Unit production costs decreased by $1.21 or 19%, to $5.16/boe mainly due to the following:

-- A general decrease of $0.50/boe at St. Albert and a decrease

of $0.54/boe due to the elimination of monthly processing

charges related to facilities acquired just prior to 2003-Q1.

The facilities were acquired pursuant to the terms of a sales

and leaseback agreement dated December 1997; and

-- A decrease of $0.17/boe due to lower unit production costs at

Alexander and Peavey/Morinville, Alberta.

Amortization and Depletion Expense (A&D) - decreased by $0.5 million or 17%, to $2.2 million. Unit A&D costs decreased by a net of $0.78/boe or 9%, to $7.11/boe due mainly to the following:

-- A decrease of $4.68/boe due to a ceiling test adjustment to

Peavey/Morinville assets taken in 2002-Q1;

-- An increase of $1.63/boe due to a non-recurring depletion rate

change applied in 2002-Q1 to Redwater, Alberta assets;

-- An increase of $1.05/boe mostly due to added unit depletion of

new crude oil production at St. Albert that commenced in late

2002;

-- An increase of $0.82/boe due mainly to revisions in our proved

producing reserves at Halkirk, Alexander, Stanmore, and

Peavey/Morinville, Alberta; and

-- An increase of $0.47/boe due to amortization of newly-acquired

leaseholds.

Exploration Expenses - decreased by $1.0 million or 54%, to $0.9 million. Unit exploration expenses decreased by a net of $2.81/boe or 49%, to $2.90/boe due mainly to the following:

-- A decrease of $4.65/boe associated with costs incurred in

2002-Q1 of unsuccessful drilling attempts, four at

Peavey/Morinville and one at Quirk Creek, Alberta; and

-- An increase of $1.77/boe in seismic costs at Wimborne,

Alberta.

Income Tax Expense - increased to $1.9 million from a recovery of $0.9 million. This expense was consistent with our pre-tax earnings. Our effective tax rate was 35.8% in 2003-Q1 and was in line with statutory tax rates. Our effective tax rate in 2002-Q1 was a recovery of 31.1%.

Other Significant Items

Liquidity and Capital Resources - our net debt decreased at the end of 2003-Q1 compared to December 31, 2002 by $0.6 million, as cash flow from operations exceeded our capital expenditures and exploration expense spending. We expect to fund our spending in 2003 from cash flow from operations and our revolving bank operating loan.

Early in the next quarter ended June 30, 2003, 780,000 employee and director stock options were exercised for $1.3 million.

Outlook - By December 31, 2003, we expect to reach a daily production rate of 5,200 boe/d, a 51% increase over our daily average production rate of 3,437 boe/d achieved in 2003-Q1. Approximately three-quarters of this increase in expected to come from increased crude oil production at St. Albert, subject to on-going regulatory processes. The balance is expected to come from natural gas at St. Albert and Cypress/Chowade.

Our drilling program for 2003 includes 20 wells, 14 of which are new and six re-entries. Of the 14 new wells, four are for development work in Alberta and seven are planned for exploratory work in northeast British Columbia.

Year-End Change and Form 20-F Transition Report - During 2002, we changed our year end to December 31 from March 31. Consequently, we filed on May 20, 2003 a transition report on Form 20-F for the nine-month period ended December 31, 2002 on SEDAR AND EDGAR. Hard copies are available upon request.

New Office Location - Effective May 26, 2003, we moved to a new address at Suite 230 - 10991 Shellbridge Way, Richmond, BC V6X 3C6. All phone and fax numbers remained unchanged.

DYNAMIC OIL & GAS, INC. is a Canadian based energy company engaged in the production and exploration of Western Canada's natural gas and oil reserves. The Company owns working interests in several central

Alberta producing properties, and in early-stage exploration properties located in southwestern and northern British Columbia.

On Behalf of the Board of Directors,

Wayne J. Babcock

President & CEO

"THE NASDAQ AND TORONTO STOCK EXCHANGES HAVE NOT REVIEWED NOR ACCEPTED RESPONSIBILITY FOR THE ACCURACY OF THIS RELEASE. SOME OF THE STATEMENTS IN THIS PRESS RELEASE ARE FORWARD-LOOKING STATEMENTS WITHIN THE MEANING OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995. 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 ALSO INCLUDE ANY OTHER PASSAGES THAT ARE PRIMARILY RELEVANT TO EXPECTED FUTURE EVENTS OR THAT CAN ONLY BE FULLY EVALUATED BY EVENTS THAT WILL OCCUR IN THE FUTURE. FORWARD LOOKING STATEMENTS IN THIS RELEASE INCLUDE, WITHOUT LIMITATION, UNCERTAINTY RELATING TO OUR BEING ABLE TO ACHIEVE THE DECEMBER 31, 2003 DAILY AVERAGE PRODUCTION ESTIMATE AND OUR EXPECTATION OF MEETING CAPITAL SPENDING PLANS WITH CASH FLOW FROM OPERATIONS AND BANK CREDIT FOR THE BALANCE OF FISCAL 2003. FORWARD-LOOKING STATEMENTS INVOLVE RISKS AND UNCERTAINTIES, INCLUDING A RISK THAT ALL DRILLING PLANS FOR FISCAL 2003 ARE ACHIEVED, AND THE OTHER RISKS DETAILED FROM TIME TO TIME IN THE COMPANY'S ANNUAL REPORT ON FORM 20-F FILED WITH THE U.S. SECURITIES AND EXCHANGE COMMISSION, LAST FILED ON MAY 20, 2003."