Dynamic Oil & Gas 6K Highlights of Results – Second Quarter Interim, Fiscal 2003 | DYOLF 29 Aug 03

August 29, 2003

Highlights of Results – Second Quarter Interim, Fiscal 2003

DYNAMIC OIL & GAS, INC.is pleased to report operational and financial highlights for the three and six-month periods ending June 30, 2003 (“2003-Q2” and “2003-Half”), compared with the three and six-month periods ending June 30, 2002 (“2002-Q2” and “2002-Half”).

Summary Highlights

In the last few days of 2003-Q2, we:

Achieved an exit rate of 4,150 boe/d. Our full-quarter average production was 3,207 boe/d; and
Tied in the first two of our five new, standing natural gas wells at Cypress/Chowade in northeast British Columbia.

Other production measures we took in 2003-Q2 were:

To temporarily holdback 393 boe/d to conduct scheduled, annual plant preventative maintenance and three-year, boiler inspection programs at facilities that handle our St. Albert production; and
To increase our daily average production of natural gas and natural gas liquids by 246 boe/d, by rerouting St. Albert production into third-party compression facilities. This helped to mitigate production declines of 640 boe/d from the same quarter last year.

In 2003-Q2 and compared to 2002-Q2, we:

Increased our gross revenues by 52% to $10.9 million;
Increased cash flow from operations by 105% to $5.4 million;
Increased our net earnings by 79% to $1.5 million; and
Increased our daily average oil production volume by 415% to 695 barrels per day.

Also during 2003-Q2 and compared to 2002-Q2, we realized the following increases in our weighted average prices:

A 67% increase in natural gas to $6.87 per mcf;
A 37% increase in natural gas liquids to $26.02 per barrel; and
A 3% increase in crude oil to $40.70 per barrel.

At the close of 2003-Q2, we:

Achieved targeted spending levels of $6.4 million for capital and exploration expense spending which represented 24% of our $26.5 million 2003 budget; and
Remained on track toward achieving our December 2003 target exit production rate of 5,200 boe/d.

Operational Highlights

(Units as stated)	2003-Q2	2002-Q2	2003-Half	2002-Half
Daily average production rates
Natural gas(mcf/d)	11,616	14,656	11,930	15,687
Natural gas liquids(bbls/d)⁽¹⁾	576	709	608	774
Crude oil(bbls/d)	695	135	726	132
All products(boe/d)⁽¹⁾	3,207	3,287	3,322	3,520
Total production (mboe)⁽¹⁾	292	299	601	637

⁽¹⁾	bbls/d = barrels per day; boe/d = barrels of oil equivalent (6 mcf = 1 bbl); mboe = thousand barrels of oil equivalent.

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Dynamic Oil & Gas, Inc. Suite 230 – 10991 Shellbridge Way, Richmond, British Columbia Canada V6X 3C6
Tel: 604/214-0550 Toll free: 1-800/663-8072 Fax: 604/214-0551 E-mail: infodynamic@dynamicoil.com Website: www.dynamicoil.com

Financial Highlights

($ 000’s unless otherwise stated)	2003-Q2	2002-Q2	2003-Half	2002-Half
Net earnings (loss)	1,472	824	4,794	(867	)
Net earnings per share($/share)	0.07	0.04	0.23	(0.04	)
Cash flow from operations⁽¹⁾	5,434	2,655	12,025	4,713
Cash flow from operations per share($/share)⁽¹⁾	0.26	0.13	0.58	0.23
Capital expenditures	5,590	551	10,852	1,927
Net debt⁽²⁾	15,902	11,625	15,902	11,625
Net debt to cash flow annualized (times)⁽³⁾	0.7:1	1.1:1	0.7:1	1.2:1

⁽¹⁾

Cash flow from operations is a non-GAAP measure that does not have standardized meaning as prescribed by GAAP and therefore may or may not 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-Q2	2002-Q2		2003-Half	2002-Half
Cash provided by operating activities (GAAP)	5,112	3,801		10,661	7,560
Changes in non-cash working capital affecting operating
activities (GAAP)	322	(1,146	)	1,364	(2,847	)
Cash flow from operations (non-GAAP)	5,434	2,655		12,025	4,713

⁽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 multiplying the three-month or six-month numbers by four or two, respectively. This method, however, does not reflect actual results for the applicable extrapolated period and as such may differ from the results achieved by this calculation.

Comparison of Significant Variances: 2003-Q2 vs 2002-Q2

Capital Expenditures –in 2003-Q2 we invested $5.6 million, 67% of which was spent on our properties at St. Albert and Wimborne, Alberta, and 23% of which was spent at Orion and Cypress/Chowade, British Columbia. In 2002-Q2 we invested $0.5 million, 80% at St. Albert and the balance at Orion.

Production Exit Rate –was 4,150 boe/d, a level that was achieved in only the last few days of 2003-Q2.

Daily Average Production Rate – decreased by a net 80 boe/d or 2%, to 3,207 boe/d. Of this net decrease, natural gas decreased by 506 boe/d or 21%, to 1,936 boe/d (11,616 mcf/d), natural gas liquids decreased by 133 boe/d or 19%, to 576 boe/d, while crude oil increased by 560 boe/d or 415%, to 695 boe/d. The main reasons for the net decrease were:

At St. Albert, daily average rates of natural gas and natural gas liquids decreased by 526 boe/d or 20%, to 2,145 boe/d due mainly to a natural decline in reservoir pressures. To help mitigate pressure declines, we re-routed production through third-party compression facilities at the end of 2003-Q2, thereby adding 246 boe/d to our production rates;
At Peavey/Morinville, Alberta, daily average rates decreased by 67 boe/d or 60%, to 62 boe/d due to production declines and a 27-day interruption during 2003-Q2 to update compression facilities; and
At Cypress/Chowade, two previously-drilled natural gas wells commenced production at the end of 2003-Q2. They produced at a combined rate of 373 boe/d for that short time. As at the end of 2002-Q3 we had three standing natural gas wells awaiting tie-in. These wells are expected to be on stream late in 2003.

Weighted Average Commodity Prices–natural gas prices increased by 67% to $6.87/mcf, natural gas liquids by 37% to $26.02/bbl and crude oil by 3% to $40.70/bbl.

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Royalties, Mineral Taxes and Alberta Royalty Tax Credits (ARTC) –increased by $1.7 million or 100%, to $3.5 million. Unit royalties expense increased by $6.08 or 105%, to $11.89 per boe due primarily to higher commodity prices and increased royalties obligations associated with production from two new St. Albert oil wells where production is burdened by an 18% overriding and a 25% crown royalty, net of ARTC.

On and effective July 7, 2003, we announced the repurchase of overriding royalty interests which burdened our total corporate production by 3%. In 2003-Q2 and 2003-Half, the overriding royalty expense was $471,135 and $794,876, respectively [2002-Q2 and 2002-Half - $195,737; $391,241, respectively]. The aggregate purchase price is to be recorded as an interest in producing leaseholds and expensed as depletion in future Statements of Operations, based on the unit-of-production method.

Production Costs – remained unchanged at $1.6 million, while unit production costs increased by a net of $0.11 or 2%, to $5.48 per boe mainly due to a decrease of $0.58 per boe related to the elimination of monthly processing charges for St. Albert facilities acquired pursuant to a sales and leaseback agreement and an increase of $0.68 per boe related to our scheduled annual plant preventative maintenance and three-year boiler inspection program at St. Albert not conducted in 2002-Q2.

Amortization and Depletion Expense (A&D) – increased by $0.5 million or 39%, to $1.9 million. Unit A&D costs increased by a net of $1.96 per boe or 43%, to $6.53 per boe due mainly to a higher leasehold asset base; new crude oil production volumes at St. Albert; and the recent annual revision to our proved producing natural gas reserves at St. Albert and Halkirk, Alberta.

Exploration Expenses – increased by $0.4 million or 88%, to $0.8 million. Unit exploration expenses increased by a net of $1.39 or 92%, to $2.90 per boe due mainly to an unsuccessful drilling attempt at Wimborne, Alberta.

General and Administrative Expenses (G&A ) – increased by $0.3 million or 59%, to $0.9 million. Unit G&A costs increased by a net of $1.17 or 63%, to $3.02 per boe. Cost increases of $1.43 per boe were spent in various areas: new staff hires; employee performance bonuses; geophysical and mapping software usage; bank-loan renegotiation fees; computer networking charges; gas marketing advice; and legal professional fees. Cost decreases of $0.26 per boe were due to overhead credits earned through the operation of properties. New production forecasted by year-end is expected to impact unit G&A costs competitively.

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

Capital Expenditures –in 2003-Half we invested $10.9 million, 44% of which was spent on our properties at St. Albert and Wimborne, Alberta, and 56% of which was spent at Orion and Cypress/Chowade, British Columbia. In 2002-Half we invested $1.9 million on land acquisitions, mainly at St. Albert.

Cash Flow from Operations (non-GAAP) - increased by a net of $7.3 million or 155%, to $4.7 million. This was the net result of a $12.6 million increase due to higher commodity prices; a $5.0 million decrease caused by lower volume sales of natural gas and natural gas liquids; an increase of $3.8 million as a result of higher volume sales of crude oil; and a decrease of $4.1 million due mainly to an increase in royalties expense.

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Net Earnings - increased by a net $5.7 million or 653%, to $4.8 million. This increase was the net result of the same factors that affected our cash flow from operations referred to above; a $0.1 million decrease due to higher amortization and depletion expense; a $0.7 million increase due to lower exploration expenses; and a $2.2 million decrease due to higher future income tax.

Other Significant Items

Liquidity and Capital Resources– during 2003-Q2, cash flows from operations, supplemented by $1.3 million in cash provided by the exercise of 780,000 stock options, exceeded our capital and exploration expense spending. As a result, our net debt decreased at the end of 2003-Q2 compared to the end of 2003-Q1 by $0.3 million. We expect to source our cash needs in the latter half of fiscal 2003 from cash flow from operations and our revolving bank operating loan.

Outlook – we continue to target a year-end daily exit rate of 5,200 boe/d. Most of the anticipated growth is expected to come from increased natural gas, natural gas liquids and crude oil production at St. Albert, subject to on-going regulatory processes. The balance is expected to come from natural gas at Cypress/Chowade, subject to the completion of pipelining and availability of third-party processing.

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

Additional reader information – this news release is a comparative summary of operational and financial results for our 2003-Q2 and 2003-Half. Because of the summary nature of this news release, readers should access our Q2 interim report at our corporate website: www.dynamicoil.com or at the regulatory filings website: www.sedar.com.

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 THAT THE VARIOUS INITIATIVES DISCUSSED ABOVE WILL, INDIVIDUALLY OR IN AGGREGATE, BE RESPONSIBLE FOR ENHANCED TRADING ACTIVITY FOR THE COMPANY’S COMMON SHARES. FORWARD-LOOKING STATEMENTS INVOLVE RISKS AND UNCERTAINTIES, INCLUDE 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”

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Dynamic Oil & Gas (DYOLF) Inactive 6-KHighlights of Results – Second Quarter Interim, Fiscal 2003