May 17, 2004
RELEASE OF FINANCIAL RESULTS FOR FISCAL 2003, 2003-Q4 AND 2004-Q1
DYNAMIC OIL & GAS, INC. announced today that it concurrently has filed with regulators and mailed to shareholders its 2003 annual audited financial statements ("Fiscal 2003") together with its unaudited interim financial statements for the first quarter ended March 31, 2004 (“2004-Q1”). Financial and operational highlights for Fiscal 2003 and 2004-Q1 are set out below. Highlights for 2003-Q4 are also provided. Because of the differing periods covered by the Fiscal 2003 and 2004-Q1 reports, readers are encouraged to review the highlights of them in this news release. As well, because of the summary nature of this news release, readers should access our Fiscal 2003 Annual Report and our 2004-Q1 Interim Report 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 2003 and 2003-Q4
Key Measures for Comparative Periods Presented| | | | | | | | Nine-Month | |
| | | | | | | | Fiscal | |
| | | | | | Fiscal | | Transition | |
| ($000’s unless otherwise stated) | 2003-Q4 | | 2002-Q4 | | 2003 | | 2002(1) | |
| Gross revenues | 9,636 | | 10,510 | | 46,848 | | 24,123 | |
| Cash flow from operations(2) | 6,205 | | 5,123 | | 23,097 | | 10,810 | |
| Cash flow from operations per share ($/share)(2) | 0.28 | | 0.25 | | 1.07 | | 0.53 | |
| Net earnings (loss) | (616 | ) | 575 | | 4,978 | | 2,004 | |
| Net earnings (loss) per share ($/share) | (0.03 | ) | 0.03 | | 0.23 | | 0.10 | |
| Daily average production | | | | | | | | |
| Natural gas (mcf/d) | 14,010 | | 13,723 | | 13,050 | | 14,174 | |
| Natural gas liquids (bbl/d) | 724 | | 708 | | 662 | | 698 | |
| Crude oil (bbl/d) | 253 | | 485 | | 610 | | 271 | |
| All products (boe/d )(3) | 3,311 | | 3,480 | | 3,447 | | 3,332 | |
| Total production (mboe)(4) | 305 | | 320 | | 1,258 | | 916 | |
| Capital expenditures | 7,211 | | 8,642 | | 31,747 | | 12,578 | |
| Net debt(5) | 19,313 | | 16,818 | | 19,313 | | 16,818 | |
| Net debt to cash flow annualized(6) | 0.8:1 | | 0.8:1 | | 0.8:1 | | 1.2:1 | |
(1)
| Fiscal 2003 coincides with our calendar year and is the first full year since we changed our fiscal year end to December 31 from March 31. The nine-month period, April 1 to December 31, 2002, represented our transition year.
|
(2)
| Cash flow from operations is a non-GAAP measure that does not have standardized meaning as prescribed by GAAP and therefore may or may not be comparable to similar measures presented by other companies. We consider it a key measure as it demonstrates our ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt.
|
| | | | | | | | | Nine-Month | |
| | | | | | | | | Fiscal | |
| | ($ 000’s) | 2003-Q4 | | 2002–Q4 | | Fiscal 2003 | | Transition 2002 | |
| | Cash provided by operating activities (GAAP) | 10,185 | | 6,861 | | 28,294 | | 11,457 | |
| | Changes in non-cash working capital affecting operating (GAAP) | (3,980 | ) | (1,738 | ) | (5,197 | ) | (647 | ) |
| | Cash flow from operations (non-GAAP) | 6,205 | | 5,123 | | 23,097 | | 10,810 | |
(3)
| boe/d = barrels of oil equivalent (6 mcf = 1 bbl).
|
(4)
| mboe = thousand barrels of oil equivalent.
|
(5)
| Net debt is working capital, as we do not have any long-term debt.
|
| (6) | Net debt divided by cash flow from operations annualized. Annualized numbers are presented by multiplying the three-month periods by four and Nine-Month Fiscal Transition 2002 by four-thirds. 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. |
Page 1 of 4
Fiscal 2003 vs Nine-Month Fiscal Transition 2002
Gross revenues, cash flow from operations and total production reached record highs in Fiscal 2003.
Gross revenues were greater in Fiscal 2003 due to a 50% increase in our realized weighted average price for natural gas and a 125% increase in our crude oil sales. Daily average production of all commodities grew by 3% to 3,447 boe/d and total production increased by 37% to 1,258 mboe. This would represent a 3% increase, if Nine-Month Fiscal Transition 2002 were annualized to 1,221 mboe.
Comparisons of our results of Fiscal 2003 versus Nine-Month Fiscal 2002 were significantly affected by the three-month difference in period length.
Our net earnings for Fiscal 2003 were the second highest in corporate history. The main reasons for this were the same key factors that generated higher gross revenues, cash flow from operations and total production outlined above. The impact of these factors on net earnings was lessened, however, by two main areas of expense - amortization and depletion and exploration expenses, which were higher by $5.7 million and $2.4 million, respectively. Amortization and depletion expense reflected: new capital expenditures related to production optimizations and leasehold acquisitions; the effects of transitioning to new reserve definitions (discussed below); and the repurchase of certain gross overriding royalty Interests that previously burdened our total current and future corporate production by 3%. Exploration expenses increased due mainly to added costs for seismic data gathering and for the drilling of two unsuccessful wells, compared to none in Nine-Month Fiscal Transition 2002.
Effective January 1, 2004, our reserves were independently determined according to a new standard adopted by Canadian regulatory authorities entitled,National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (NI 51-101). The previous standard was entitled,“Guide for Engineers and Geologists Submitting Oil and Gas Reports to Provincial Securities Administrators” (National Policy No. 2-B). Reserve definitions under these two standards differ and therefore are not directly comparable. To be more comparable to NI 51-101, however, the industry has established for year-over-year reconciliation purposes that January 2003 estimated reserves under National Policy 2-B be restated from “proved plus probable” reserves to “proved plus one-half probable” reserves.
During Fiscal 2003, our total proved plus probable ‘assigned’ reserves decreased by 506 mboe or 5%, to 9,218 mboe. We added 294 mboe to proved reserves through extensions and discoveries, however, under NI51-101, revisions decreased by 1,608 mboe. Taking into account annual production, proved reserves decreased by 2,571 mboe or 31%, to 5,599 mboe, 73% of which was natural gas. We added 143 mboe to probable reserves through extensions and discoveries, and 1,922 through revisions. Overall, probable reserves increased by 2,065 mboe or 133%, to 3,620 mboe, 81% of which was natural gas.
2003-Q4 vs 2002-Q4
Total production of natural gas and natural gas liquids both increased by 2% in 2003-Q4 over 2002-Q4. However, our total production did not change materially between quarters due to a decrease in crude oil production by 48%. The increase in our total natural gas production was mostly due to two new wells at Cypress/Chowade that were not yet on stream in 2002-Q4. The decrease in average daily crude oil production was mostly due to the decline in flow-rates from one well at St. Albert that began producing in 2002-Q4.
Our gross revenuesdecreased by $0.9 million or 8%, to $9.6 million. The key factors involved in this decrease were lower weighted average realized prices combined with the decreased crude oil volumes discussed above.
Our weighted average prices realized for natural gas were higher by 4% (to $5.73 from $5.50 per mcf), while prices for crude oil were lower by 11% (to $36.94 from $41.57 per barrel).
Our cash flow from operations increased by $1.1 million or 21%, to $6.2 million due to the same factors affecting our gross revenues discussed above, accompanied by a net decrease of $2.0 million in cash expenses. Most of the net decrease in cash expenses was due to lower royalties and current income taxes.
Page 2 of 4
Our net earnings decreased by $1.2 million, to a loss of $0.6 million due mainly to the same factors affecting our cash flow from operations discussed above, accompanied by increases of $1.3 million and $1.0 million in exploration expenses, and amortization and depletion expense, respectively. Exploration expenses reflected higher costs for seismic data gathering costs. Amortization and depletion expense reflected higher costs mainly due to the repurchase in July 2003 of certain gross overriding royalty interests that previously burdened our total current and future corporate production by 3%.
During 2003-Q4, our total capital investment was $7.2 million: 3% was for new land acquisitions at Cypress/Chowade; 95% was for drilling, completions and equipping work - mostly in the development of Cypress/Chowade and St. Albert; and 2% was for facilities and pipelining - mostly on compressor modifications and upgrades in St. Albert.
Highlights of Results – 2004-Q1
Key Measures for Comparative Periods Presented| ($000’s unless otherwise stated) | 2004-Q1 | | 2003–Q1 | |
| Gross revenues | 10,975 | | 14,308 | |
| Cash flow from operations(1) | 5,749 | | 6,592 | |
| Cash flow from operations per share ($/share)(1) | 0.26 | | 0.32 | |
| Net earnings (loss) | (788 | ) | 3,393 | |
| Net earnings (loss) per share ($/share) | (0.04 | ) | 0.17 | |
| Daily average production | | | | |
| Natural gas (mcf/d) | 14,580 | | 12,252 | |
| Natural gas liquids (bbl/d) | 684 | | 639 | |
| Crude oil (bbl/d) | 273 | | 756 | |
| All products (boe/d )(2) | 3,387 | | 3,437 | |
| Total production (mboe)(3) | 308 | | 309 | |
| Capital expenditures | 8,409 | | 5,262 | |
| Net debt(4) | 26,161 | | 16,189 | |
| Net debt to cash flow annualized(5) | 1.1:1 | | 0.6:1 | |
(1) (2) (3) (4) and (5)See footnotes to previous table.
Production of natural gas and natural gas liquids increased in 2004-Q1 by 19% and 7% over 2003-Q1, respectively Total production on an mboe basis did not change materially between quarters due to a crude oil production decrease of 64%. Our weighted average prices realized for natural gas dropped from $8.09 to $6.56 per mcf, a softening of 19% from 2003-Q1, while prices for crude oil were lower by 11%, from $49.58 to $44.30 per barrel.
Our gross revenuesdecreased in2004-Q1 from 2003-Q1 by $3.3 million or 23%, to $11.0 million. The key factors involved in this decrease were lower weighted average realized prices for all commodities and volume variances caused by changes in our production mix. Price-based variances were responsible for 76% of the overall decrease and 24% was due to volume-based variances.
The increase in our total natural gas production was mostly due to four new wells at Cypress/Chowade that, upon their start-up in early March 2004, increased our daily rates to approximately 4,200 boe/d. In late March, daily production from these wells was constrained by limits on our access to third-parties facilities, resulting in an average daily production for 2004-Q1 of 3,387 boe/d. To help address constraint concerns, we have budgeted our half of the cost to construct a 30 mmcf/d sour gas plant and associated facilities later in 2004.
The decrease in average daily crude oil production was mostly due to the decline in flow-rates from one well at St. Albert that began producing just prior to 2003-Q1.
Page 3 of 4
Our cash flow from operations in 2004-Q1 decreased from 2003-Q1 by $0.9 million or 13%, to $5.7 million due to the same factors affecting our gross revenues discussed above accompanied by a net decrease of $2.4 million in cash expenses. Most of the net decrease in cash expenses was due to lower royalties and current income taxes.
Our net earnings in 2004-Q1 decreased from 2003-Q1 by $4.3 million, to a loss of $1.0 million due mainly to the same factors affecting our cash flow from operations descibed above, accompanied by an increase of $3.3 million or 370%, to $4.2 million in our exploration expenses.
Of the $4.2 million we invested on exploration expenses in 2004-Q1, $2.6 million was for a 44 square-kilometer 3D proprietary seismic program at Orion and a further $1.4 million was related to our share of costs for drilling two unsuccessful exploration wells at Cypress/Chowade. Although we consider investments in seismic data important to our future growth strategy, we treat those investments, along with unsuccessful drilling attempts, as an expense in the period in which they are incurred.
During 2004-Q1, our total capital investment was $8.4 million, of which 27% was for new new land acquisitions at Cypress/Chowade, 33% was for drilling, completions and equipping work mostly at Cypress/Chowade and St. Albert, and 39% was for facilities and pipelining (primarily on the construction of a 32-kilometer pipeline at Cypress/Chowade).
Our Fiscal 2004 target daily average and exit production rates are 3,900 and 4,400 per boe/day, respectively. Our target production rates do not include potential increases resulting from work being conducted during the year on certain undeveloped properties. A discussion of these properties, the amount of capital budgeted for them in 2004 and their potential impact on 2004 production is included in the Management’s Discussion and Analysis section of our Fiscal 2003 Annual Report.
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 LIT IGATION REFORM ACT OF 1995. FORWARD LOOKING STATEMENTS INCLUDE ALL PASSAGES CONTAINING VERBS SUCH AS 'AIMS, ANTICIPATES, BELIEVES, EST IMATES, 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, W ITHOUT LIMITAT ION, UNCERTAINTY RELATING TO OUR BEING ABLE TO MEET FISCAL 2004 BUDGET EXPECTATIONS AND PRODUCTION TARGETS. FORWARDLOOKING STATEMENTS INVOLVE RISKS AND UNCERTAINTIES, INCLUDING A RISK THAT ALL DRILLING AND FACIL ITIES CONSTRUCTION PLANS FOR FISCAL 2004 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. "
Page 4 of 4
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
