Dynamic Oil & Gas 6K Release of Financial Results for Fiscal 2004 and 2004-Q4 | DYOLF 31 Mar 05

March 31, 2005

RELEASE OF FINANCIAL RESULTS FOR FISCAL 2004 AND 2004-Q4

DYNAMIC OIL & GAS, INC. announced today that it has filed with regulators its Fiscal 2004 annual audited financial statements, management’s discussion and analysis, and its estimated reserves reported on Form NI 51-101 ("Fiscal 2004"). Financial and operational highlights for Fiscal 2004 are set out below. Highlights for 2004-Q4 are also provided. Because of the summary nature of this news release, readers should access our Fiscal 2004 Annual Report on Form 20-F for further details at our corporate website: www.dynamicoil.com or at the regulatory filings websites: www.sedar.com or www.sec.gov/edgar.

Highlights of Results – Fiscal 2004 and 2004-Q4

Key Measures for Comparative Periods Presented

($000’s unless otherwise stated)	2004–Q4		2003-Q4		Fiscal 2004		Fiscal 2003
Gross revenues	9,822		9,636		40,806		46,848
Cash flow from operations⁽¹⁾	4,372		6,205		19,421		23,097
Cash flow from operations per share($/share)⁽¹⁾	0.17		0.28		0.82		1.07
Net (loss) earnings	(11,528	)	(616	)	(12,281	)	4,978
Net (loss) earnings per share($/share)	(0.49	)	(0.03	)	(0.52	)	0.23

Daily average production
Natural gas(mcf/d)	11,073		14,010		12,518		13,050
Natural gas liquids(bbl/d)	554		724		572		662
Light/medium crude oil(bbl/d)	145		253		174		610
Heavy crude oil(bbl/d)	242		-		61		-
All products(boe/d )⁽²⁾	2,787		3,311		2,893		3,447
Total production (mboe)⁽³⁾	256		304		1,059		1,258

Capital investment program⁽⁴⁾	12,303		7,211		36,836		31,747
Net debt⁽⁵⁾	25,513		19,313		25,513		19,313
Net debt to cash flow annualized⁽⁶⁾	1.5:1		0.8:1		1.3:1		0.8:1

⁽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. The following table shows how we derive our non-GAAP measure from GAAP measures.

($ 000’s)	2004-Q4		2003-Q4		Fiscal 2004	Fiscal 2003
Cash provided by operating activities (GAAP)	4,406		10,185		15,111	28,294
Changes in non-cash working capital affecting operating (GAAP)	(34	)	(3,980	)	4,310	(5,197	)
Cash flow from operations (non-GAAP)	4,372		6,205		19,421	23,097

⁽²⁾	boe/d = barrels of oil equivalent (6 mcf = 1 bbl).
⁽³⁾	mboe = thousand barrels of oil equivalent.
⁽⁴⁾	For Fiscal 2004, we changed the method of reporting capital transactions. We now report capital transactions under the title, “Capital Investment Program” instead of the former title, “Capital Expenditures”. The difference in methods is that Capital Investment Program includes exploration expenses relating to seismic and unsuccessful drilling efforts, whereas Capital Expenditures did not. Seismic and unsuccessful drilling costs comprise the majority of our Exploration expense 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 yearly Capital Investment Program. All comparative amounts have been restated accordingly.
⁽⁵⁾	Net debt divided by cash flow from operations annualized. Annualized numbers are presented by multiplying the three-month periods by four. This method, however, does not reflect actual results for applicable extrapolated periods and therefore actual results may differ from the extrapolations generated by this application.
⁽⁶⁾	Net debt divided by cash flow from operations annualized.

Fiscal 2004 vs Fiscal 2003
Record-high weighted average prices received for natural gas of $6.67 per mcf and light/medium crude oil of $50.03 per barrel led the way in ranking our Fiscal 2004 gross revenues and cash flow from operations as second-highest in our corporate history, behind Fiscal 2003. Gross revenues in Fiscal 2004 were $40.8 million

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

compared to $46.8 million in Fiscal 2003 and cash flow from operations was $19.4 million compared to $23.1 million, respectively. The effect of our weighted average prices is the first key performance measure that impacts our gross revenue, cash flow from operations and ultimately net earnings. Their record-high impact in Fiscal 2004 increased gross revenues over Fiscal 2003 by $2.7 million.

After accounting for price variances, which are largely controlled by the market forces of supply/demand for our commodities, the second key performance measure that impacts us is the variance in our levels of production between periods. Our Fiscal 2004 production levels were 16% below those for Fiscal 2003, which decreased gross revenues by $8.7 million. Total production in Fiscal 2004 was 1,059 mboe and total daily average production was 2,893 boe per day, compared to 1,258 mboe and 3,447 boe per day, respectively, in Fiscal 2003.

Of the decrease in gross revenues attributed to volume changes between Fiscals 2004 and 2003, over 90% was due to production decreases in light/medium crude oil. Most of these decreases related to relatively sharp production declines in two St. Albert wells, both of which reached payout of our original capital expenditures within a few weeks after first coming into production in early Fiscal 2003. Volume changes that contributed to the remaining decrease in gross revenues were the net result of production decreases in natural gas liquids and production increases in heavy crude oil.

In October 2004, we made a new-pool discovery of heavy crude oil at Mantario East in southeast Saskatchewan. After drilling our discovery well, we followed up with an aggressive drilling program and by the year-end, we had drilled 13 wells, resulting in five producing, six cased and standing and two unsuccessful wells. Heavy crude oil production commencing in the last two months of Fiscal 2004 increased gross revenues by $0.5 million.

During Fiscal 2004, $0.9 million of our gross revenues decrease was due to declining production of liquid-rich natural gas. Our liquid-rich natural gas originates from our St. Albert field, where we are experiencing a predictable rate of natural decline.

While volumes of liquid-rich natural gas declined at St. Albert during Fiscal 2004, new volumes of lean natural gas came into production at Cypress/Chowade due to the start-up of three new wells. The impact of these increases and decreases in natural gas volumes was a net decrease in our gross revenues of $0.4 million.

After accounting for the two key performance measures discussed above - price and volume variances - cash flow from operations decreased by $1.9 million due to an increase in our cost of production. On a per boe basis, unit production costs may differ according to product-type, field location and age of field. As an example, in Fiscal 2004, unit production costs increased by 52% to $8.44 per boe. Approximately half of the increase was due to remoteness associated with new natural gas production in northeast British Columbia, where time is needed to build economies of scale. The other half of the increase is mainly due to additional variable costs associated with compression fees, and the general effect caused by coverage of fixed costs by declining production from our Alberta fields.

Our net loss in Fiscal 2004 of $12.3 million was contributed to in a significant way by the third key performance measure - the degree of our success in establishing or replacing proved reserves. The costs of unsuccessful drilling efforts and downward revision to proved reserves are reflected in two expense categories – exploration expenses, and amortization and depletion.

Exploration expenses increased in Fiscal 2004 by $10.3 million over Fiscal 2003, contributing significantly to our net loss. Our strategies have consistently been to grow proved reserves primarily through drilling and specific, targeted acquisitions. Accordingly, in Fiscal 2004, we participated in drilling a corporate record-high of 28 wells, ten of which were unsuccessful, compared to 14 wells in Fiscal 2003, two of which were unsuccessful. This difference, combined with failed efforts to establish proved reserves in five other wells that were drilled prior to Fiscal 2004 explains most of the increase in our exploration expenses.

Amortization and depletion expense was another significant contributor to our net loss. It increased in Fiscal 2004 by $12.2 million, 88% of which was mainly due to a decrease in proved producing reserves at Cypress/Chowade. The balance was due to higher capital-to-reserve ratios in connection with most of our Alberta properties, increased amortization for leaseholds acquired during Fiscal 2004, and new depletion associated with our Mantario East assets.

We incurred $36.8 million on our Fiscal 2004 Capital Investment Program and advanced our strategies in the following ways:

We spent $4.2 million on the acquisition of new lands, over half of which was spent in the Cypress/Chowade area. Most of the remainder was spent at Mantario East and on other associated Saskatchewan properties;
We drilled and completed 28 wells (22.0 net) and equipped most of them for a total cost of $22.1 million. Our overall net working interest drilling success rate was 68%. Of twelve wells that targeted natural gas, six were unsuccessful. The other six, three at Cypress/Chowade, two at Orion and one at Sandgren, were completed as cased and standing wells. We drilled two wells that targeted light/medium crude oil at St. Albert, one of which was successful. The remaining 14 wells targeted heavy crude oil at Mantario East and Flaxcombe, 11 of which were either producing or cased and standing as at December 31, 2004. Three were unsuccessful;
Our investment in facilities, pipelining and other assets grew by $6.7 million. Over 85% of this amount was invested in northeast B.C., most of which was for our participation in the construction of an 8”, 19 kilometer pipeline at Cypress/Chowade. The remaining 15% was primarily for the optimization and upgrading of certain production facilities at St. Albert; and
We invested $3.7 million on seismic data activity, over 87% of which was for a two-phase, 3D seismic program covering 90 square kilometers on our early-stage exploration property at Orion.

While we do not consider income taxes as a key performance measure, they did impact our bottom-line results significantly in Fiscal 2004. Consistent with our pre-tax loss of $19.7 million, our total current and future income taxes changed from an expense of $2.2 million in Fiscal 2003 to a recovery of $7.4 million in Fiscal 2004. After accounting for certain reconciling items, the effective rate of our income tax recovery was 37.7% .

On March 1, 2005, we announced our reserves effective December 31, 2004. We also released at that time our capital investment program and production targets for Fiscal 2005.

2004-Q4 vs 2003-Q4
Our gross revenues increased by a net of $0.2 million or 2% to $9.8 million. There were two factors that contributed to the net increase. Gross revenues increased due to strong weighted average prices realized for natural gas, natural gas liquids and light/medium crude oil. Gross revenues decreased due to lower production of natural gas and light/medium crude oil.

Our weighted average prices realized were higher for natural gas by 17% (to $6.70 from $5.53 per mcf), natural gas liquids by 30% (to $33.25 from $25.58 per barrel) and light/medium crude oil by 55% (to $57.14 from $36.94 per barrel).

Total production of natural gas and natural gas liquids decreased by 22% in 2004-Q4 from 2003-Q4. While light/ medium crude oil production decreased by 54%, production of heavy crude oil commenced from our new-pool discovery at Mantario East. The main reason for production decreases in natural gas and natural gas liquids was due to a predictable rate of natural decline in production from our Alberta properties. Production of light/medium crude oil decreased by 43% due mainly to relatively sharp production declines in two St. Albert wells, both of which reached payout of our original capital expenditures within a few weeks after first coming into production in early Fiscal 2003.

Our cash flow from operations decreased by $1.8 million or 30% to $4.4 million. After accounting for the increase in gross revenues, the decrease in cash flow from operations was mainly due to increased cash expenses. Most of the increase in cash expenses was related to production costs ($0.9 million) and current income taxes ($1.1 million). We had no current income tax expense in 2004-Q4 compared to a recovery in 2003-Q3.

Our net loss increased by $10.9 million to $11.5 million due mainly to the same factors affecting cash flow from operations discussed above, accompanied by the net result of certain increases and decreases in non-cash expenses. Increases were due to amortization and depletion ($10.3 million), and exploration expense ($6.1 million) and were mainly due to the same reasons discussed above in the year-to-year comparisons. Decreases were to stock-based compensation expense ($0.1 million) and future income tax recovery/expense ($7.2 million).

During 2004-Q4, we incurred $12.3 million on our capital investment program. Of this total, 47% was incurred in southwestern Saskatchewan, mostly at Mantario East. Another 35% was incurred at Cypress/Chowade and Orion in northeastern British Columbia. The balance was incurred in Alberta, most of which was at St. Albert. Most of our capital investment in the quarter was for drilling, completions and equipping.

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. We own working interests in producing and early-stage exploration properties located in central Alberta, southwestern Saskatchewan, and northeastern and southwestern 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 MEET FISCAL 2005 BUDGET EXPECTATIONS AND PRODUCTION TARGETS. FORWARD-LOOKING STATEMENTS INVOLVE RISKS AND UNCERTAINTIES, INCLUDING A RISK THAT ALL DRILLING AND FACILITIES CONSTRUCTION PLANS FOR FISCAL 2005 ARE ACHIEVED, A RISK THAT OUR HEAVY CRUDE OIL COULD BECOME UNECONOMIC TO PRODUCE DUE TO ANY ONE OF, OR A COMBINATION OF, THE FOLLOWING FACTORS: RESERVE REVISIONS; HIGHER FLOW RESISTANCE; LOWER PRICES RELATIVE TO LIGHT/MEDIUM CRUDE OIL; AND HIGHER TRANSPORTATION COSTS, 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 MARCH 31, 2005."

Dynamic Oil & Gas (DYOLF) Inactive 6-KRelease of Financial Results for Fiscal 2004 and 2004-Q4