Dynamic Oil & Gas 6K Current report

File No. 0-17551

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 6-K

Report on Foreign Issuer

Pursuant to Rule 13a-16 or 15d-16
Of the Securities Exchange Act of 1934

For the Period of May 14, 2003

DYNAMIC OIL & GAS, INC.
(Registrant’s name)

Airport Executive Park
#205, 10711 Cambie Road
Richmond, B.C.
Canada V6X 3G5
(Address of principal executive offices)

Indicate by check mark whether the Registrant files or will file annual reports under cover of Form 20F or Form 40-F

Form 20-F X

Form 40-F

Indicate by check mark whether the Registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934

Yes

No X

If “Yes” is marked, indicate below the file number assigned to the Registrant in connection with Rule 12g3-2(b): Not applicable.

Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	Dynamic Oil & Gas, Inc
	(Registrant)



Dated: 05-14-03	By: /s/ Mike Bardell
	Mike Bardell, Chief Financial Officer &
	Corporate Secretary

-2-

May 14, 2003

Highlights For Q3 and Transition Year Ended December 31, 2002

DYNAMIC OIL & GAS, INC. is pleased to report operational and financial highlights for:

Our third quarter ended December 31, 2002 (Q3, 2002) compared with our third quarter ended December 31, 2001 (Q3, 2001); and
The nine-month period ended December 31, 2002 compared with the twelve-month period ended March 31, 2002.

Our most recently filed annual report covered the twelve-month period ended March 31, 2002. Since then, we changed our fiscal year end to December 31. Today’s news release covers the nine-month transition period ended December 31, 2002 and for ease of reading, we refer to this period as “Fiscal Transition 2002”. We refer to the twelve-month period ended March 31, 2002 as “Fiscal 2002”.

							Fiscal
							‘Nine-Month’
		Three Months Ended Dec 31					Transition	Fiscal

(All numbers in thousands, unless indicated)		2002	2001		% Chg		2002	2002		% Chg

Gross revenue		10,511	6,258		68		24,123	26,402		(9	)
Cash flow from operations⁽¹⁾		5,037	1,991		153		10,723	11,337		(5	)
- per share, basic($)		0.25	0.10		150		0.53	0.55		(4	)
Earnings (loss)		664	(3,389	)	120		1,978	(3,519	)	156
- per share, basic($)		0.04	(0.17	)	124		0.10	(0.17	)	159
Capital expenditures		8,642	2,024		327		12,578	22,111		(43	)

Daily production	- Natural gas (mcf/d)	13,723	17,542		(22	)	14,174	15,107		(6	)
	- NGL’s(bbls/d)	708	600		18		698	631		11
	- Crude oil(bbls/d)	485	75		547		271	76		257
	- Equiv(boe/d, 6:1)	3,480	3,598		(3	)	3,332	3,225		3
Total production	- Equiv(mboe, 6:1)	320	331		(3	)	916	1,177		(22	)
Annualized production⁽²⁾	- Equiv (mboe)	320	331		(3	)	1,221	1,177		4

Wtd. avg. prices	- Natural gas($/mcf)	5.50	3.26		69		4.36	3.81		14
	- NGL’s($/bbl)	24.69	16.77		47		20.90	19.30		8
	- Crude oil($/bbl)	41.57	29.07		43		41.40	34.33		21

	As at	Dec 31		Mar 31
		2002		2002		% Chg

Working capital		(16,818	)	(13,281	)	(266	)
Total assets		43,646		37,152		17
Operating loan		11,075		14,750		(25	)
Shareholder’s equity		18,245		16,593		10
Common shares outstanding		20,272		20,462		(1	)

(1)	Cash flow from operations = “Cash provided by operating activities” plus “Changes in non-cash working capital affecting operating activities” in our Statements of Cash Flows. 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.

(2)	Annualized production is presented by applying the nine-month transition numbers multiplied by four-thirds, however, this method does not reflect actual results for the three-month extrapolated period and such results may differ from the result achieved by this calculation.

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Dynamic Oil & Gas, Inc. Airport Executive Park Suite 205 – 10711 Cambie Road Richmond, British Columbia Canada V6X 3G5
Tel: 604/214-0550 Toll free: 1-800/663-8072 Fax: 604/214-0551 E-mail: infodynamic@dynamicoil.com Website: www.dynamicoil.com

Q3, 2002 vs Q3, 2001 Comparisons
Capital invested -increased by $6.6 million or 327%, to $8.6 million over Q3, 2001 due mainly to increased drilling activity. A significant portion of our total capital invested in Q3, 2002 was related to drilling five exploration wells at Cypress/Chowade in northeast B.C. Our capital invested in Q3, 2001 was spent in Alberta toward drilling and tying-in one well at St. Albert and six others with accompanying facilities at Halkirk.

Cash flow from operations -increased by a net $2.5 million or 97%, to $5.0 million over Q3, 2001 mainly due to the following factors:

An increase of $1.1 million due to a 548% increase in crude oil production;
A net decrease of $0.8 million due to a 15% decrease in natural gas and natural gas liquids production;
An increase of $3.9 million due to an 74% aggregate increase in our weighted average commodity prices;
A decrease of $2.3 million due to increases in royalties expense, production costs and general and administrative expenses; and
An increase of $0.6 million due to a decrease in current income tax expense.

Earnings -increased by a net $4.1 million or 120%, to $0.7 million over Q3, 2001 mainly due to the following factors:

A net increase of $2.5 million from the same factors affecting cash flow from operations explained above;
An increase of $4.0 million due to a decrease in amortization and depletion expense;
An increase of $0.4 million due to a decrease in exploration expenses; and
A decrease of $2.8 million due to an increase in future income tax expense.

Total production -decreased by a net 11 mboe or 3%, to 320 mboe from Q3, 2001. This was mainly due to increases of 10 mboe at St. Albert, Alexander and Simonette offset by decreases of 21 mboe at Peavey/Morinville, Halkirk Westlock and Stanmore.

Daily average production rates -decreased by a net 118 boe/d or 3%, to 3,480 boe/d from Q3, 2001. The main reasons for this net decrease were:

A decrease at Peavey/Morinivlle of 192 boe/d due to production declines;
A decrease at St. Albert of 348 boe/d in natural gas and natural gas liquids due to production declines; and
An increase at St. Albert of 410 boe/d in new crude oil production.

Weighted average commodity prices - increased by $2.24/mcf or 69%, to $5.50/mcf for natural gas; by $7.92/bbl or 47%, to $24.69/bbl for natural gas liquids; and by $12.50/bbl or 43%, to $41.57/bbl for crude oil over Q3, 2001.

Royalties - increased by $1.5 million or 140%, to $2.6 million over Q3, 2001 mainly due to our higher weighted average commodity prices.

Operating costs - increased by $0.5 million or 33%, to $2.0 million over Q3, 2001. Our unit operating costs increased by $1.68 or 37%, to $6.19 per boe due to the same reasons described in the operating cost comparisons below.

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Amortization and depletion expense –decreased by $4.0 million or 53%, to $3.5 million from Q3, 2001 mainly due to a ceiling test adjustment taken on our Peavey/Morivnille assets in Q3, 2001.

Fiscal Transition 2002 vs Fiscal 2002 Comparisons
Capital invested -decreased by $9.5 million or 43%, to $12.6 million from Fiscal 2002. There are two key reasons for this decrease:

Fiscal Transition 2002 was a comparatively shorter reporting period; and
We spent $14.4 million in Fiscal 2002 on acquiring additional working interests at our St. Albert property.

During Fiscal Transition 2002 we invested $6.1 million or 49% of our total capital expenditures in Alberta and $6.5 million or 51% in British Columbia. Of the total spent in Alberta, $4.9 million was at St. Albert and Halkirk on exploration, development and facilities, while $1.2 million was spent mostly on acquiring new working and royalty interests at St. Albert. Of the total spent in British Columbia, $5.1 million was spent on exploration at Cypress/Chowade and $1.4 million was spent mostly acquiring additional Orion lands.

Cash flow from operations -decreased by a net $0.6 million or 5%, to $10.7 million from Fiscal 2002 mainly due to the following factors, some of which were affected by the comparatively shorter reporting period:

A decrease of $5.3 million due to a 22% decrease in total production;
An increase of $3.0 million due to an 18% aggregate increase in our weighted average commodity prices; and
An increase of $1.7 million due mainly to a 16% decrease in royalty expense.

Earnings -increased by a net $5.5 million or 156%, to $2.0 million over Fiscal 2002 mainly due to the following factors: A net decrease of $0.6 million from the same factors affecting cash flow from operations explained above;

An increase of $5.7 million due to a decrease in depletion expense;
An increase of $3.3 million due to a decrease in exploration expenses; and
A decrease of $2.9 million due to an increase in future income tax expense.

Total production -decreased by 261 mboe or 22%, to 916 mboe from Fiscal 2002 mainly due to the comparatively shorter reporting period. On an annualized basis, however, total production for 2002 would increase by 44 mboe or 4%, to 1,221 mboe.

Daily average production rates -increased by a net 107 boe/d or 3%, to 3,332 boe/d over Fiscal 2002. Of this net increase, natural gas decreased by 155 boe/d or 6%, to 2,362 boe/d (14.2 mmcf/d), natural gas liquids increased by 67 boe/d or 11%, to 698 boe/d, while crude oil increased by 195 boe/d or 257%, to 271 boe/d. The net 107 boe/d increase was due to the following:

A decrease of 71 boe/d in production of natural gas and natural gas liquids at St. Albert due to natural declines in reservoir pressures which we expect to offset in 2003 by drilling and tying-in additional wells and adding third-party compression;
An increase of 188 boe/d in crude oil production due to the addition of three new oil wells, the largest of which commenced production in the period for 61 days at a daily average rate of 498 boe/d;

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A net decrease of 10 boe/d resulting from increases of 159 boe/d at Halkirk, Alexander and Simonette offset by decreases of 169 boe/d at Peavey/Morinville at Virgo, most of which was due to declining production of natural gas at Peavey/Morinville.

Weighted average commodity prices -increased by $0.55/mcf or 14%, to $4.36/mcf for natural gas; by $1.60/bbl or 8%, to $20.90/bbl for natural gas liquids; and, by $7.07/bbl or 21%, to $41.40/bbl for crude oil over Fiscal 2002. In general, natural gas prices strengthened in the latter part of Fiscal Transition 2002 due to cold weather in the eastern US, while crude oil prices strengthened due to geopolitical uncertainties and tighter supplies.

Royalties -decreased by $1.0 million or 16%, to $5.3 million from Fiscal 2002 due mainly to the comparatively shorter reporting period.

Operating costs -decreased by $0.4 million or 6%, to $5.5 million from Fiscal 2002 due mainly to the comparatively shorter reporting period, however unit production costs increased by $1.00 or 20%, to $5.97 per boe. The main reasons for this unit cost increase were:

Higher costs for electricity, well maintenance and for plant turnaround work that was not conducted in Fiscal 2002, all at St. Albert; and
Increased field compression charges for Alexander production.

Amortization and depletion expense (A&D) -decreased by $5.7 million or 47%, to $6.4 million from Fiscal 2002 due mainly to the comparatively shorter reporting period. Our unit A&D decreased by a net of $3.32 or 32%, to $7.02 per boe due mainly to a ceiling test adjustment of $3.66 per boe taken on our Peavey/Morinville assets in Fiscal 2002.

Exploration expenses -decreased by $3.3 million or 71%, to $1.4 million from Fiscal 2002 due mainly to a decrease in costs associated with unsuccessful drilling attempts of $3.5 million or 91%, to $0.3 million. All drilling attempts were successful in Fiscal Transition 2002, however, in Fiscal 2002 a total of ten wells were written off to dry hole expense, six of which were at Peavey/Morinville, one each at Quirk Creek, Alexander and Orion, and one re-entry/workover at St. Albert.

Income tax expenses -increased to $1.2 million from a recovery of $1.9 million, an increase that was consistent with our pre-tax earnings. Our effective tax rate of 37.1% was in line with statutory tax rates.

Working capital and operating loan -our working capital deficit of $16.8 million as at December 31, 2002 includes the operating loan balance with our corporate bank of $11.1 million. This deficit increased by $3.5 million or 266% over our March 31, 2002 deficit due mainly to increased capital spending activity at Cypress/Chowade late in the period. Our March 31, 2002 deficit included $14.8 million in operating loan debt mainly due to our acquisition of additional working interests at St. Albert.

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 northeastern British Columbia.

On Behalf of the Board of Directors,

Wayne J. Babcock
President and Chief ExecutiveOfficer

"THE NASDAQ AND TORONTO STOCK EXCHANGES HAVE NOT REVIEWED NOR ACCEPTED RESPONSIBILITY FOR THE ACCURACY OF THIS RELEASE.

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