Dynamic Oil & Gas (DYOLF)

[amarksp]

Dynamic Oil & Gas, Inc.: Third Quarter Interim Report and Outlook for Fiscal 2003
Monday December 1, 9:07 am ET
http://biz.yahoo.com/bw/031201/15299_1.html

VANCOUVER, British Columbia--(BUSINESS WIRE)--Dec. 1, 2003--DYNAMIC OIL & GAS, INC. is pleased to report operational and financial highlights for the three and nine-month periods ending September 30, 2003 ("2003-Q3" and "2003-Nine"), compared with the three and nine-month periods ending September 30, 2002 ("2002-Q3" and "2002-Nine").
Summary Highlights

In this quarter and compared to the same calendar quarter last year, we:

Increased our daily average production by 19% to 3,831 boe per day - a quarterly historical record;
Increased our gross revenues by 87% to $12.0 million;
Increased cash flow from operations by 61% to $4.9 million; and
Increased net earnings by 97% to $1.0 million.
Also during this quarter and compared to the same quarter last year, we realized the following changes in our weighted average prices:

A 66% increase in natural gas to $5.80 per mcf;
A 39% increase in natural gas liquids to $26.17 per barrel; and
A 5% decrease in crude oil to $40.53 per barrel.
On July 7, 2003, we repurchased for an aggregate price of $6.5 million, certain gross overriding royalty interests that previously burdened our total current and future corporate production by 3%. The aggregate price was paid by the issuance of 1,050,666 common shares and the payment of $1.0 million in cash. For comparison purposes, previous royalties paid pursuant to these interests were:

During the period January 1 to July 7, 2003 - $0.8 million; and
During the period January 1 to September 30, 2002 - $0.7 million.
At the close of this quarter, our:

Committed cash resources of $10.5 million for capital and exploration expense spending represented 32% of our $33.0 million 2003 budget. On a year-to-date basis, we committed cash resources of $21.3 million or 65% of our 2003 budget; and
Daily production exit rate was 3,679 boe per day. Our exit rate target for December 2003 is 5,200 boe per day, subject to the following:
new natural gas production expected at Cypress/Chowade in northeast B.C., pending completion of pipelining and availability of third-party processing; and
new crude oil production expected at St. Albert, Alberta, pending successful outcomes of up-hole completions in two separate well-bores and one, new deep- drilling event.
Operational Highlights

(Units as stated) 2003-Q3 2002-Q3 2003-Nine 2002-Nine
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Daily average production
rates
Natural gas (mcf/d) 14,292 14,148 12,726 15,168
Natural gas liquids
(bbls/d)(1) 707 677 641 741
Crude oil (bbls/d) 742 192 731 152
All products (boe/d)(1) 3,831 3,227 3,493 3,421
Total production (mboe)(1) 353 297 954 934
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(1) bbls/d = barrels per day; boe/d = barrels of oil equivalent
(6 mcf = 1 bbl); mboe = thousand barrels of oil equivalent.



Financial Highlights

($ 000's unless otherwise stated)

2003-Q3 2002-Q3 2003-Nine 2002-Nine
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Gross revenues 11,980 6,418 37,212 20,220
Net earnings (loss) 965 491 5,759 (376)
Net earnings (loss)
per share ($/share) 0.04 0.02 0.27 (0.02)
Cash flow from
operations(1) 4,866 3,031 16,891 7,744
Cash flow from operations
per share ($/share)(1) 0.22 0.15 0.80 0.38
Capital expenditures 10,489 2,109 21,341 4,036
Net debt(2) 16,552 12,739 16,552 12,739
Net debt to cash flow
annualized (times)(3) 0.9:1 1.1:1 0.7:1 1.2:1
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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 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-Q3 2002-Q3 2003-Nine 2002-Nine
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Cash provided by
operating activities
(GAAP) 7,447 794 18,109 8,354
Changes in non-cash
working capital
affecting operating
activities (GAAP) (2,581) 2,237 (1,217) (610)
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Cash flow from operations
(non-GAAP) 4,866 3,031 16,891 7,744
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(2) Net debt is working capital. We have no long-term debt.

(3) Net debt divided by cash flow from operations annualized.
Annualized numbers are presented by multiplying the three-month or
nine-month numbers by four or four-thirds, 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-Q3 vs 2002-Q3

Capital Expenditures - in 2003-Q3 we invested $13.7 million. Included in that amount, $9.7 million was for the July 7, 2003 repurchase of certain gross overriding royalty interests that burdened our total current and future corporate production by 3%. The carrying value of the repurchase is comprised of the aggregate repurchase price of $6.5 million that we paid for the royalty interests (see Summary Highlights), plus the cost of related future income taxes of $3.2 million as is required under Canadian GAAP.

Of the $4.0 million remainder, 58% was spent on our St. Albert and Wimborne properties in central Alberta, and 42% was spent on our Orion and Cypress/Chowade properties in northeastern British Columbia.

In 2002-Q3 we invested $2.1 million, 76% at St. Albert and Halkirk in Alberta, and 24% at Orion and Cypress/Chowade in British Columbia.

Cash Flow from Operations (non-GAAP) - increased by a net of $1.8 million or 61%, to $4.9 million. This was the net result of a $3.4 million increase due mainly to higher realized weighted average prices for natural gas and natural gas liquids; a $2.1 million increase due to a 286% increase in crude oil production; and a decrease of $3.7 million due mainly to increases in royalties and current income tax expense ($2.3 million and $1.0 million, respectively).

Net Earnings - increased by a net $0.5 million or 97%, to $1.0 million. This increase was the net result of the same factors that affected our cash flow from operations referred to above, accompanied by an increase of $1.8 million in amortization and depletion expense and a decrease of $0.5 million in future income tax expense.

Daily Average Production Rate - increased by a net 604 boe/d or 19%, to 3,831 boe/d. Of this net increase, natural gas increased by 24 boe/d or 1%, to 2,382 boe/d (14,292 mcf/d), natural gas liquids increased by 30 boe/d or 4%, to 707 boe/d, while crude oil increased by 550 boe/d or 286%, to 742 boe/d. The main reasons for the net increase were:

At St. Albert, daily average rates of natural gas and natural gas liquids decreased by 146 boe/d or 6%, to 2,405 boe/d (14,430 mcf/d) due mainly to a natural decline in reservoir pressures. Daily rates of crude oil increased by 550 boe/d or 288%, to 741 boe/d due to three new oil wells that were either not yet discovered or not yet in full production in 2002-Q3;
At Cypress/Chowade, daily average rates increased by 260 boe/d (1,560 mcf/d) from two wells that were not yet discovered in 2002-Q3. As at the end of 2002-Q3 we had three standing natural gas wells awaiting tie-in, pending completion of pipelining and availability of third-party processing.
Weighted Average Commodity Prices - natural gas prices increased by 66% to $5.80/mcf, natural gas liquids by 39% to $26.17/bbl, while crude oil decreased by 5% to $40.53/bbl.

Royalties, Mineral Taxes and Alberta Royalty Tax Credits - increased by $2.3 million or 218%, to $3.3 million. Unit royalties expense increased by a net $5.85 ($6.38/boe less $0.53/boe) or 168%, to $9.34/boe. The $6.38/boe increase was primarily due to: higher commodity prices ($3.80/boe); royalty obligations associated with production from two new St. Albert oil wells ($1.88/boe); and a non-repetitive crown royalty adjustment in 2002-Q3 ($0.70/boe). The $0.53/boe decrease was due to the July 7, 2003 repurchase of gross overriding royalty interests that previously burdened our total current and future corporate production by 3%.

Production Costs - increased by $0.2 million or 11%, to $2.1 million. Unit production costs decreased by a net of $0.42 or 7%, to $5.92/boe mainly due to the elimination of monthly processing charges for St. Albert facilities acquired pursuant to a sales and leaseback agreement.

Amortization and Depletion Expense (A&D) - increased by $1.8 million or 118%, to $3.4 million. Unit A&D costs increased by a net of $4.38/boe or 83%, to $9.68/boe mainly due to: an increase in depletion at St. Albert due to higher capital-to-reserve ratios for recent crude oil discoveries and natural gas optimizations ($2.05/boe); an increase due to additional depletion related to the July 7, 2003 repurchase of gross overriding royalty interests that previously burdened our total current and future corporate production by 3% ($2.00/boe); and an increase due to amortization of a higher leasehold base ($0.44/boe).

Exploration Expenses - increased by $0.1 million or 13%, to $0.6 million. Unit exploration expenses decreased by a net of $0.09 or 5%, to $1.60/boe. Current quarter drilling expense includes the cost of one unsuccessful drilling attempt at Halkirk, Alberta.

General and Administrative Expenses (G&A) - increased by $0.2 million or 41%, to $0.8 million. Unit G&A costs increased by a net $0.36 or 19%, to $2.29/boe. Cost increases of $0.51/boe were spent in various areas: new staff hires; geophysical and mapping software usage; corporate insurance; computer networking charges; and gas marketing advice. Cost decreases of $0.15/boe were due to our earning more overhead credits associated with the operation of properties.

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

Capital Expenditures - in 2003-Nine we invested $24.5 million, $9.7 million of which was for the July 7, 2003 gross overriding royalty repurchase (see Capital Expenditures comment above). Of the $14.8 million remainder, 48% was spent on our properties at St. Albert, Halkirk and Wimborne, Alberta, and 52% was spent at Orion and Cypress/Chowade, British Columbia.

In 2002-Nine we invested $4.0 million, 83% at St. Albert, Alberta, and the balance at Orion and Cypress/Chowade, British Columbia.

Cash Flow from Operations (non-GAAP) - increased by a net $9.1 million or 118%, to $16.9 million. This was the net result of: higher weighted average prices realized in all commodities ($15.6 million); a decrease due to lower volume sales of natural gas and natural gas liquids ($5.5 million); an increase due to higher volume sales of crude oil ($6.9 million); an increase in royalties expense ($6.0 million); and an increase in current income tax expense ($1.6 million).

Net Earnings - increased by a net $6.1 million to $5.8 million from a deficit of $0.4 million. This increase was the net result of the same factors that affected our cash flow from operations referred to above, accompanied by: an increase in amortization and depletion expense ($1.9 million); an increase in future income tax expense ($1.7 million); and a decrease in exploration expenses ($0.6 million).

Other Significant Items

Liquidity and Capital Resources - during 2003-Q3, our capital resources consisted of the following: cash flow from operations; cash provided by the exercise of stock options; common stock issued to repurchase certain gross overriding royalty interests (see Summary Highlights); and available bank lines of credit. Net debt increased by $0.7 million in 2003-Q3 compared to 2002-Q3, as our capital expenditures and exploration expenses exceeded cash flow from operations.

Outlook - Our exit rate target for December 2003 is 5,200 boe/d, reflecting anticipated growth over our 2003-Q3 daily average of 3,831 boe/d. This growth is expected to be 15% crude oil and 85% natural gas. New crude oil production is expected to come from St. Albert and is subject to the successful outcomes of up-hole completions in two separate well-bores and one, new drilling event scheduled in the fourth quarter of 2003. New natural gas production is expected to come mainly from Cypress/Chowade in northeast B.C. and is subject to the completion of pipelining and availability of third-party processing.

The two up-hole oil completions have tested crude oil and associated gas in the Nisku D-2 formation. The wells were tied-in and initial production tests began in late November 2003. The new well targeting the Leduc D-3 oil formation in the 'north' pool, was spudded in mid-November and has now reached target depth. A service rig is being moved on to the location to penetrate the top of the reef and test for oil potential. If successful, the Company expects to increase oil production, add new reserves and replace oil production from two existing Leduc D-3 wells in the 'south' pool that declined in 2003-Q3. Two additional north pool wells, originally scheduled for 2003 and delayed to allow for community consultation, have been rescheduled for 2004.

Also at St. Albert, efforts to optimize natural gas recovery from the low-pressure Ostracod zone have been successful. Two wells were drilled using under-balanced drilling techniques in 2003-Q2 and tied-in during 2003-Q3. These wells are presently producing, allowing us to better manage the recovery rates of remaining Ostracod reserves.

At Cypress/Chowade in northeastern B.C., Dynamic and partners drilled and completed their sixth successful natural gas well late in 2003-Q3. Of the first five, one is producing through third-party facilities and four are in the process of being completed, tested and tied in. Based on earlier seismic, several new exploration and development locations in the area have been defined. In November 2003, Dynamic conducted further proprietary 2D seismic on 100% farm-in lands that were recently-acquired at Chowade.

Two new zones have been recently completed in two of the five earlier wells. From each of these zones, natural gas has flowed in excess of 3.5 mmcf/d on extended production tests. Dynamic and partner are aggressively pursuing the construction of a pipeline connection to Duke Energy's Sikhanni gas plant. Completion is expected in early 2004.

At Cypress/Chowade, our drilling plans for the remainder of 2003 include three wells, two of which are currently drilling. One of the wells is a $4.0 million deep-gas test in which the Company has a 20% interest before payout and a 28% interest after payout. The well is expected to reach target depth early in January 2004. Of the remaining two wells, (Dynamic 30%), one is an exploration well expected to reach target depth in December 2003 and the other is a development outpost well expected to spud before year end.

In 2003-Q3, our 2003 drilling program was revised from 14 wells to ten. One well was cancelled and three were shifted forward to early 2004. Our six-well re-entry program, originally budgeted in 2003, has been completed. We expect to remain close to our 2003 capital and exploration expense budget of $33.0 million due to replacement of four exploration wells with two higher-cost ones in northeast B.C.

Additional reader information - this news release includes comparative operational and financial information for our 2003-Q3 and 2003-Nine. Because of the summary nature of this news release, readers should access our 2003-Q3 interim report at our corporate website for further details: 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 producing and early-stage exploration properties in central Alberta, southwestern and northeastern British Columbia.

On Behalf of the Board of Directors,
Wayne J. Babcock
President & CEO