6-K 1 dol6k.htm Untitled Document

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 Months of August and September, 2002

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 20-F 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: October 8th, 2002 By: /s/ Mike Bardell
    Mike Bardell, Chief Financial Officer &
    Corporate Secretary

 



Corporate Information
Airport Executive Park
205 – 10711 Cambie Road
Richmond, BC
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
(For Canadian equivalent of “Edgar”, see www.sedar.com)

Directors
Wayne J. Babcock
John A. Greig
David J. Jennings
John Lagadin
Jonathan A. Rubenstein
Donald K. Umbach

Officers
Wayne J. Babcock,
President & CEO
Donald K. Umbach,
Vice President & COO
James R. Britton,
Vice President, Exploration
Michael A. Bardell,
CFO & Corporate Secretary

Stock Transfer Agent
CIBC Mellon Trust Company
1600 – 1066 W. Hastings St. Vancouver, BC Canada V6E 3X1

Bank
National Bank of Canada
407 Eighth Avenue S.W. Calgary, AB Canada T2P 1E5

Lawyers
Irwin, White & Jennings
2620 – 1055 W. Georgia St. Vancouver, BC Canada V6E 3R5
Perkins Coie LLP
6th Floor – 1620 26th St. Santa Monica, CA, USA 90404

Accountants
Ernst & Young LLP
700 West Georgia Street Vancouver, BC Canada V7Y 1C7

Trading Symbols NASDAQ:DYOLF
TSE:DOL

 

  

PRESIDENT’S MESSAGE

To Our Shareholders and Prospective Shareholders:

Budget Update, Capital Expenditures and Exploration Expenses

On May 28, 2002, I announced our capital expenditures and exploration budget for fiscal 2003. Under the budget, we expected to spend an estimated $18.1 million during the period April 1, 2001 to March 31, 2003. Of that amount, nearly one-third was for drilling horizontal wells in the Orion area of northeast British Columbia.

On June 10, 2002, I announced the terms of our agreement with a large independent Canadian oil and gas company to farmout a significant portion of our Orion land interests. The large independent, or farmee, is known to be very active in the Greater Sierra area of northeastern British Columbia. Under the terms of the farmout agreement1, the farmee will have the right to earn an interest in three Orion blocks totaling 28,334 acres by drilling up to four horizontal test wells into the Upper-Devonian, Jean Marie formation. In exchange, we will reduce our working interest in the blocks from a net weighted average working interest of approximately 78% to 32%.

Many of you have asked whether the farmout deal with the large independent has freed up budget funds for other projects. The simple answer is, yes. One example came just after the close of this quarter, when on July 30, 2002, I announced the terms of a participation and farmin agreement in the Cypress area of northern British Columbia. Cypress is a new prospect for Dynamic, located in the foothills approximately seventy miles northwest of Fort St. John.

The Cypress deal2 gives us the right to earn an average working interest of 35% in approximately 5,120 acres by participating at 50% in the cost of drilling two exploratory test wells. The first well started drilling mid-August, 2002 and is expected to take until around the first of October to reach total depth. The target depth is 2,600 meters and its cost is expected to be $2.5 million ($1.25 million our share). The second well, an option well, is expected to cost $1.8 million ($0.9 million our share).

As the year progresses, we expect to undertake other projects with the budget funds freed up as a result of the Orion farmin agreement.

Operational results, Q1, fiscal 2003

In this quarter, the Carbondale Gas Plant owned by Atco Midstream Ltd. was shut down fourteen days for regular plant maintenance. Atco chooses to shut down the Carbondale Gas Plant each year around the same time when natural gas prices are generally thought to be at their lowest in the annual cycle. The Villeneuve Gas Plant also owned by Atco will need an annual maintenance turnaround too and as it stands right now, we are expecting it to be shut down for about five days in September, 2002. That way, both plants are down in gas-demand shoulder months rather than peak demand times.

We estimate that the Carbondale shut-down interrupted our total average daily production by approximately 350 barrels of oil equivalent (“boe) per day or 10% in Q1 fiscal 2003. Our daily average production rate, with the interruption, was 3,267 boe per day.

Drilling activity

In this quarter, we were busy with drilling permits and drillsite preparations, and over the next three quarters we expect to drill or participate in up to twenty-one wells. Of those, we expect to drill twelve development wells on our St. Albert and Halkirk properties in Alberta and nine exploratory wells on our properties in central Alberta and northeast British Columbia. I will be pleased to report our success rates as things unfold.

Wayne J. Babcock, President and CEO

1 For more specific details, please read the June 10, 2002 news release on our website at www.dynamicoil.com.
 2 For more specific details, please read the July 30, 2002 news release on our website at www.dynamicoil.com.

 

(All numbers stated in Canadian dollars, unaudited)

INTERIM REPORT HIGHLIGHTS

(All numbers in the tables below are in $(000’s), unless otherwise indicated)

Three Month Period Ending June 30
Statements of Operations   2002 %Chg 2001 %Chg 2000
Gross revenue 7,194 8 6,649 32 5,021
Funds flow from operations 2,655 (12 ) 3,010 21 2,485
    per share, basic ($) 0.13 (13 ) 0.15 15 0.13
    per share, diluted ($) 0.13 (7 ) 0.14 17 0.12
EBITDA1 2,849 57 1,814 (19 ) 2,233
    per share, basic ($) 0.14 56 0.09 (18 ) 0.11
    per share, diluted ($) 0.14 75 0.08 (20 ) 0.10
Earnings 824 27 649 (40 ) 1,077
    per share, basic ($) 0.04 33 0.03 (40 ) 0.05
    per share, diluted ($) 0.04 33 0.03 (40 ) 0.05
Capital expenditures 551 (97 ) 17,382 1,659 988
Daily production
    Natural gas (mcf/d) 14,656 39 10,554 (7 ) 11,367
    Natural gas liquids (bbls/d) 709 74 408 (16 ) 484
    Oil (bbls/d) 135 322 32 (11 ) 36
    All products (boe2/d) 3,287 50 2,199 (9 ) 2,414
    Total production (mboe) 299 50 200 (9 ) 220
Weighted average sales prices
    Natural gas ($/mcf) 4.11 (28 ) 5.67 46 3.89
    Natural gas liquids ($/bbl) 19.00 (33 ) 28.21 23 23.02
    Oil ($/bbl) 39.38 (2 ) 40.25 3 39.16
    Equivalent ($/boe) 24.06 (27 ) 33.03 41 23.50
Field netback3 ($/boe) 12.80 (29 ) 18.12 42 12.74

1EBITDA is earnings before interest, taxes, amortization and depletion. EBITDA 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.
2boe = barrels of oil equivalent (6mcf = 1bbl); mboe = one thousand boe.
3field netback = revenues less royalties and production costs.

Period Ending June 30 March 31
Balance Sheets 2002 %Chg 2001 2002
Working capital (11,625 ) 21 (14,709 ) (13,280 )
Total assets 34,081 (19 ) 42,069 37,152
Shareholders’ equity 17,417 (16 ) 20,709 16,593
Common shares outstanding (000’s) (authorized 60 million)
   basic 20,462 1 20,217 20,365
   diluted 20,471 (5 ) 21,541 20,467
   period end 20,462 – 20,375 20,462

BALANCE SHEETS

As at June 30 March 31
2002 2001 2002
Assets
Current:
Cash and cash equivalents $ – $ 17,016 $ –
Accounts receivable 3,607,158 3,758,397 5,979,532
Prepaid expenses 435,237 143,162 365,227
Total current assets 4,042,395 3,918,575 6,344,759
Future income tax asset 265,000 – 279,000
Natural gas and oil interests 29,602,367 37,961,685 30,365,636
Capital assets 171,464 188,300 162,499
$ 34,081,226 $ 42,068,560 $ 37,151,894
Liabilities & Shareholders’ Equity
Current:
Bank indebtedness 641,593 – 842,812
Operating loan 10,700,000 10,775,000 14,750,000
Accounts payable & accrued liabilities $ 3,554,805 $ 6,068,250 $ 3,611,314
Income taxes payable 771,097 1,784,787 421,360
Total current liabilities 15,667,495 18,628,037 19,625,486
Deferred gain on sale 72,065 274,187 109,327
Future removal and site restoration 924,868 585,065 824,098
Future income taxes – 1,872,000 –
Total liabilities 16,172,650 21,359,289 20,558,911
Shareholders’ equity
Share capital 20,914,522 20,756,020 20,914,522
Deficit (3,497,724 ) (46,749 ) (4,321,539 )
Total shareholders’ equity 17,416,798 20,709,271 16,592,983
$ 34,081,226 $ 42,068,560 $ 37,151,894

(All numbers stated in Canadian dollars, unaudited)

STATEMENTS OF OPERATIONS AND DEFICIT

First Quarter Ended June 30
2002 2001 2000
Revenue
Natural gas, liquids and oil sales $ 7,194,396 $ 6,649,374 $ 5,021,337
Royalties (1,760,776 ) (2,005,799 ) (1,153,759 )
Production costs (1,605,426 ) (1,017,552 ) (1,001,493 )
3,828,194 3,626,023 2,866,085
Alberta royalty tax credit 22,262 37,953 58,550
3,850,456 3,663,976 2,924,635
Expenses
General and administrative (schedule 1) 552,756 672,133 357,710
Interest expense on operating loan 151,820 3,911 81,788
Interest income (1,121 ) (22,066 ) –
703,455 653,978 439,498
Earnings from operations
   before the following: 3,147,001 3,009,998 2,485,136
Amortization and
   depletion (schedule 2) 1,368,345 833,365 439,255
Exploration expenses (schedule 3) 451,202 1,178,103 373,984
Gain on sale of oil interests (2,139 ) – (39,901 )
Earnings before taxes 1,329,593 998,530 1,711,798
Current income tax expense 491,778 359,000 –
Future income tax expense (recovery) 14,000 (9,000 ) 635,000
Earnings 823,815 648,530 1,076,798
Deficit, beginning of period (4,321,539 ) (695,279 ) (10,379,392 )
Premium on purchase and cancellation
      of common shares – – (29,917 )
Deficit, end of period $ (3,497,724 ) $ (46,749 ) $ (9,332,511 )
Earnings per share
      basic $ 0.04 $ 0.03 $ 0.05
      diluted $ 0.04 $ 0.03 $ 0.05

STATEMENTS OF CASH FLOWS

First Quarter Ended June 30
2002 2001 2000
Operating activities
Earnings $ 823,815 $ 648,530 $ 1,076,798
Add (deduct) items not involving cash:
   Amortization and depletion 1,368,345 833,365 439,255
   Future income tax expense 14,000 350,000 635,000
Exploration expenses 451,202 1,178,103 373,984
Gain on sale of oil interests (2,139 ) – (39,901 )
Funds flow from operations 2,655,223 3,009,998 2,485,136
Changes in non-cash working capital
   affecting operating activities 1,145,933 489,280 369,083
Cash provided by operating activities 3,801,156 3,499,278 2,854,219
Financing activities
Bank indebtedness (201,219 ) 114,300 –
Share repurchases – – (89,690 )
Operating loan (4,050,000 ) 10,775,000 (2,800,000 )
Cash provided by (used in)
   financing activities (4,251,219 ) 10,889,300 (2,889,690 )
Investing activities
Purchase of capital assets (35,635 ) (74,564 ) (15,085 )
Natural gas and oil interests (514,898 ) (17,306,958 ) (972,611 )
Exploration expenses (451,202 ) (1,178,103 ) (373,984 )
Proceeds on sale
   of oil interests 2,139 – 39,901
Changes in non-cash working capital
   affecting investing activities 1,449,659 694,615 (4,997 )
Cash provided by (used in)
   financing activities 450,063 (17,865,010 ) (1,326,776 )
Increase (decrease) in
   cash and cash equivalents – (3,476,432 ) (1,362,247 )
Cash and cash equivalents
   beginning of period – 3,493,448 1,441,881
   end of period $ – $ 17,016 $ 79,634
Funds flow from operations per share
   basic $ 0.13 $ 0.15 $ 0.12
   diluted $ 0.13 $ 0.14 $ 0.12

(All numbers stated in Canadian dollars, unaudited)

SCHEDULE 1:
GENERAL AND ADMINISTRATIVE

First Quarter Ended June 30
2002 2001 2000
Advertising and promotion $ 50,715 $ 49,011 $ 57,319
Insurance 41,809 11,494 –
Interest 495 52,573 3,385
Office and printing 127,844 133,533 48,191
Professional fees 90,585 177,702 55,573
Provincial capital taxes 8,918 20,992 –
Regulatory and other fees 15,733 7,750 5,996
Rent 22,912 21,855 21,513
Salaries and benefits 259,538 211,133 167,091
Telephone 4,424 3,879 3,559
Travel 7,567 5,638 903
Cost recoveries (77,783 ) (23,427 ) (5,820 )
$ 552,756 $ 672,133 $ 357,710

SCHEDULE 2:
AMORTIZATION AND DEPLETION

Amortization and depletion $ 1,304,838 $ 853,444 $ 537,272
Future removal, site restoration 100,769 45,335 (15,229 )
Amortization, deferred financing costs – – 565
Amortization, deferred gain on sale (37,262 ) (65,414 ) (83,353 )
$ 1,368,345 $ 833,365 $ 439,255

SCHEDULE 3:
EXPLORATION EXPENSES

Drilling $ 186,274 $ 1,016,045 $ 295,726
Seismic data activity 252,179 136,544 62,765
Non-producing lease rentals (1,087 ) 10,994 3,968
Property investigations 13,836 14,520 11,525
$ 451,202 $ 1,178,103 $ 373,984

SUMMARY OF OPTIONS OUTSTANDING

Share options as at June 30, 2002
Number Exercise Price $ Expiry Date
740,000 1.72 22 April, 2003
40,000 1.72 14 July, 2003
45,000 1.45 24 January, 2005
30,000 1.75 01 August, 2005
353,000 2.10 29 September, 2005
21,000 2.17 01 March, 2006
90,000 1.70 04 April, 2006
60,000 2.25 15 April, 2006
307,500 1.75 28 February, 2007
112,500 1.72 17 August, 2010
18,750 2.10 29 September, 2010
52,500 2.15 30 April, 2011
60,000 2.10 23 August, 2011
57,500 1.65 30 April, 2012
1,987,750

STATEMENT OF EXECUTIVE
REMUNERATION

We did not pay any cash compensation to our directors, in their capacities as such. During Q1 fiscal 2003, we had four executive officers to whom salaries and payments made pursuant to royalty agreements with three of those executive officers totaled $314,666.

MANAGEMENT’S DISCUSSION
AND ANALYSIS

The following discussion and analysis should be read in conjunction with our Unaudited Financial Statements included in this first quarter (“Q1”) interim report. Our Unaudited Financial Statements have been prepared in accordance with generally accepted accounting principles in Canada.

Unless otherwise noted, dollar amounts in the tables below are in thousands of Canadian dollars, and production volumes are before royalties. When production and sales volume amounts of all products are combined, they are expressed on a barrels-of-equivalent (“boe”) basis, where gas volumes in thousands of cubic feet (“mcf”) are converted to boe on a 6:1 basis (6 mcf = 1 boe).

Results of Operations

Our funds flow from operations for Q1 fiscal 2003 was $2.7 million while our earnings were $0.8 million. Weighted average prices for natural gas and crude oil contributed solidly to our financial results while weighted average prices for natural gas liquids were less supportive. During the quarter, the Carbondale Gas Plant (“Carbondale”) owned by Atco Midstream Ltd. was shut down for approximately two weeks for regular annual plant maintenance. We process a significant portion of natural gas and natural gas liquids production from our St. Albert field in Alberta through Carbondale. Including the Carbondale shut-down, production averaged 3,287 boe per day throughout the quarter. Had Carbondale been fully operational during the entire quarter, we estimate our daily average production for the quarter would have increased by approximately 350 boe per day.

During Q1 fiscal 2003, our capital expenditures were $0.5 million, most of which were spent on drilling and developing our interests at St. Albert. Also, during the quarter, our financial capacity remained strong. Funds generated from operations were used to repay our existing bank credit facility and finance our capital investment program. At June 30, 2002, we had an unused balance of $10.3 million available through our revolving, demand credit facility. As we progress with our fiscal 2003 capital expenditures and exploration expense budget of $18.1 million, we expect to employ a significant portion of the unused balance.

New Accounting Standard

Effective April 1, 2002, we adopted the new Canadian Institute of Chartered Accountants standard with respect to the accounting for stock-based compensation and other stock-based payments. The new standard requires stock-based payments to non-employees, direct awards of stock and awards that call for settlement in cash or other assets that are outstanding or are granted for fiscal years beginning on or after January 1, 2002 be accounted for using the fair value method of accounting. The fair value method is encouraged for all other employee stock-based compensation awards, but other methods of accounting, such as the intrinsic value method, are permitted.

Under the fair value method, compensation expense is measured at the grant date and recognized over the service period using an option pricing model. Under the intrinsic value method, compensation expense is determined as the difference between the market price of the underlying stock and the exercise price of the stock option at grant date.

While we account for stock-based payments to non-employees using the fair value method, we have elected to use the intrinsic value method of accounting for stock options granted to employees and directors under our stock option plan. Had compensation expense for our employees and directors been measured based on the fair value method, there would have been no impact on our basic and diluted earnings per common share for the first quarter ended June 30, 2002.

Production Volumes

Average daily natural gas production in Q1 fiscal 2003 increased by 4,102 mcf per day (“mcf/d”) or 39%, to 14,656 mcf/d over Q1 fiscal 2002. Average daily natural gas liquids production, compared to Q1 fiscal 2002, increased by 301 barrels per day (“bbls/d”) or 74%, to 709 bbls/d. Average daily oil production compared to Q1 fiscal 2002 increased by 103 bbs/d or 322 %, to 135 bbls/d.

On an equivalent basis, production of all products in Q1 fiscal 2003 increased by 1,088 boe/d or 50%, to 3,287 boe/d over Q1 fiscal 2002, the major items being:

  • An increase of 1,076 boe/d mainly due to the acquisition of additional working interest at St. Albert after Q1 fiscal 2002;
  • An increase of 196 boe/d due to six new wells at Halkirk that began production after Q1 fiscal 2002;
  • An increase of 67 boe/d due to one well at Alexander that began production after Q1 fiscal 2002;
  • A decrease of 240 boe/d at Peavey/Morinville due to declining productivity.

Total production of all our commodities in Q1 fiscal 2003 increased by 99 thousand barrels of oil equivalent (99 “mboe”) or 50%, to 299 mboe over Q1 fiscal 2002. The table below shows that total production of all our commodities increased by 50% over Q1 fiscal 2002 and that there was a shift in commodity type to total production. The percentage of gas to total production decreased by 8%, while the percentages of natural gas liquids and oil production to total production increased by 16% and 300% respectively over Q1 fiscal 2002.

For first quarter ended June 30/02 June 30/01 June 30/00
Commodity type to total production Percent % Chg Percent % Chg Percent
Natural gas 74 (8 ) 80 3 78
Natural gas liquids 22 16 19 (5 ) 20
Oil 4 300 1 (50 ) 2
Total (mboe) 299 50 200 (9 ) 220

Product Prices

The weighted average price for our natural gas sales in Q1 fiscal 2003 decreased by $1.56 per mcf or 28%, to $4.11 per mcf from Q1 fiscal 2002. Similarly, the weighted average price for our liquids sales in Q1 fiscal 2003 increased by $9.21 per barrel or 33%, to $19.00 per barrel over Q1 fiscal 2002. Oil prices were relatively constant between Q1 fiscal 2003 and Q1 fiscal 2002.

During Q1 fiscal 2003, 53% of our total natural gas sales were at a weighted average price of $4.04 per mcf into aggregator portfolios that are comprised of a mix of spot, short-term and long-term contracts. The remaining 47% of our natural gas sales were at a weighted average price of $4.19 per mcf into non-aggregated spot markets. In Q1 fiscal 2002, 76% of our total natural gas sales were sold at a weighted average price of $5.57 per mcf into aggregator portfolios and 24% were sold at a weighted average price of $5.99 per mcf into non-aggregator spot markets. All of our natural gas liquids and oil were sold directly into non-aggregated spot markets under arm’s length contracts during Q1 fiscal 2003 and Q1 fiscal 2002.

MANAGEMENT’S DISCUSSION AND ANALYSIS, CONT’D

Revenue - Natural Gas, Natural Gas Liquids and Oil Sales

Total revenue in Q1 fiscal 2003 increased by $0.5 million or 8%, to $7.2 million over Q1 fiscal 2002. Of total revenue in Q1 fiscal 2003, 76% was from natural gas, 17% from natural gas liquids and 7% from oil. In Q1 fiscal 2002, 82% of total revenue was from natural gas, 16% from natural gas liquids and 2% from oil.

For first quarter ended June 30/02 June 30/01 June 30/00
Revenue Total % Chg Total % Chg Total
Natural gas 5,489 – 5,488 41 3,879
Natural gas liquids 1,205 15 1,046 3 1,014
Oil 500 335 115 (10 ) 128
Total 7,194 8 6,649 32 5,021

In Q1 fiscal 2003, higher volumes sales increased revenues by $2.4 million over Q1 fiscal 2002 and lower weighted average prices for natural gas and natural gas liquids decreased revenues by $1.8 million from Q1 fiscal 2002, thereby resulting in the comparative net increase of $0.5 million (see comparative variance table below).

In Q1 fiscal 2003, sales volumes of natural gas, mainly from our St. Albert field, increased revenues by $1.5 million or 277% over Q1 fiscal 2002. Offsetting this increase was an equal decrease in natural gas revenues of $1.5 million or 277% caused by the variance in weighted average prices between Q1 fiscal 2003 and Q1 fiscal 2003.

Sales volumes of natural gas liquids, also from St. Albert, increased revenues in Q1 fiscal 2003 by $0.5 million or 92% over Q1 fiscal 2002. Offsetting this increase was a decrease in natural gas liquids revenues of $0.3 million or 63% caused by the variance in weighted average prices between Q1 fiscal 2003 and Q1 fiscal 2002.

Weighted average prices of oil were relatively even between Q1 fiscal 2003 and fiscal Q1 2002, while production increases from St. Albert resulted in increased revenues in Q1 fiscal 2003 of $0.4 million or 71% over Q1 fiscal 2003.

For comparative first quarters ended June 30 2002 vs 2001 2001 vs 2000
Increase (decrease) in revenues of: Amount % Amount %
Natural gas
   resulting from variances in price (1,510 ) (277 ) 1,776 109
   resulting from variances in volume sales 1,511 277 (168 ) (10 )
Natural gas liquids
   resulting from variances in price (341 ) (63 ) 229 14
   resulting from variances in volume sales 500 92 (198 ) (12 )
Oil
   resulting from variances in price (2 ) - 3 -
   resulting from variances in volume sales 387 71 (14 ) (1 )
Total 545 100 1,628 100

Royalties and Mineral Taxes

Total royalties including mineral taxes decreased in Q1 fiscal 2003 by $0.1 million or 4%, to $1.7 million from Q1 fiscal 2002. In Q1 fiscal 2003, our crown royalties remained relatively even while freehold and overriding royalties decreased by $0.3 million or 23%, to $1.0 million from Q1 fiscal 2002. Most of the 23% decrease in our overriding royalties was due to lower commodity prices used to calculate royalty bases.

In Q1 fiscal 2003, our mineral taxes payable to the government of Alberta increased by $0.2 million or 155%, to $0.4 million over Q1 fiscal 2002 due mostly to a tax reassessment of a prior period. Alberta Royalty Tax Credits (“ARTC”) in Q1 fiscal 2003 decreased by 42% from Q1 fiscal 2002. This was strictly due to lower royalties on wells eligible for ARTC.

For first quarter ended June 30/02 June 30/01 June 30/00
Royalties and mineral taxes Total % Chg Total % Chg Total
Crown 418 (9 ) 457 6 431
Freehold and Overriding 961 (23 ) 1,249 122 563
Freehold mineral taxes* 382 155 150 88 80
1,761 (5 ) 1,856 73 1,074
ARTC (22 ) (42 ) (38 ) (164 ) (59 )
Total 1,738 (4 ) 1,818 79 1,015

* Based on current industry trend, we reclassified mineral taxes from Production Costs to Royalties in Q1 fiscal 2003. For comparison purposes, prior year amounts have been restated in the Statements of Operations and Deficit.

Production Costs

Our unit production costs in Q1 fiscal 2003 increased by $0.6 million or 58%, to $1.6 million over Q1 fiscal 2002. On a boe basis, this represented a $0.28 per boe increase or 6%, to $5.37 per boe. During Q1 fiscal 2003, our unit production costs were $5.09 per boe at St. Albert, $4.99 per boe at Halkirk and $7.61 per boe at Peavey/Morinville. Comparatively, our unit production costs during Q1 fiscal 2002 were $4.99 per boe at St. Albert and $5.88 per boe at Peavey/Morinville. Our unit production cost increase in Q1 fiscal 2003 over Q1 fiscal 2002 at Peavey/Morinville was due to fixed costs to operate wells with decreasing productivity.

For first quarter ended June 30/02 June 30/01 June 30/00
Production costs Total % Chg Total % Chg Total
Production costs - total 1,605 58 1,018 8 1,081
Per boe ($) 5.37 6 5.09 18 4.92

* Based on current industry trend, the company reclassified mineral taxes from production costs to royalties in fiscal 2003. For comparison purposes, prior years have been restated in the Statement of Operations and Deficit.

General and Administrative Expenses

Our total general and administrative expenses decreased in Q1 fiscal 2003 by $0.1 million or 18%, to $0.6 million from Q1 fiscal 2002. The $0.1 million was the net result of certain decreases and increases. The decreases to interest and professional fees incurred in Q1 fiscal 2002 were associated with the St. Albert acquisition. The increases to salaries, insurance costs and cost recoveries incurred in Q1 fiscal 2003 were associated with our becoming Operator of the St. Albert field.

Interest Expense

At the end of Q1 fiscal 2003, $10.7 million of our revolving, demand credit line with our corporate bank was outstanding. In Q1 fiscal 2002, the Company had no outstanding balance against its demand credit line. Interest expense was $0.2 million in Q1 fiscal 2003.

Amortization and Depletion

Our amortization and depletion expense in Q1 fiscal 2003 increased by $0.5 million or 64%, to $1.4 million over Q1 fiscal 2002. This increase was due to higher production and an increased depletion rate at our St. Albert field in Q1 fiscal 2003 over Q1 fiscal 2002. The increased depletion rate at St. Albert was caused by our acquisition in Q1 fiscal 2002 of additional interests in the field.

Exploration Expenses

Our exploration expenses in Q1 fiscal 2003 decreased by $0.7 million or 62%, to $0.5 million from Q1 fiscal 2002. In Q1 fiscal 2002, we expensed $1.1 million for drilling two unsuccessful wells compared with $0.2 million expensed in Q1 fiscal 2003. We had no unsuccessful drilling attempts in Q1 fiscal 2003. Seismic costs during Q1 fiscal 2003 increased by $0.1 million or 85%, to $0.3 million over Q1 fiscal 2002.

Income Taxes

Current income tax expenses and the provision for future income tax expenses grow commensurate with funds flow from operations and earnings. During Q1 fiscal 2003, our current income taxes increased by $0.2 million or 45%, to $0.5 million over Q1 fiscal 2002. The effective income tax rate during Q1 fiscal 2003 was an expense of 38.0%, compared with a full-year income tax recovery rate of 35.1% for fiscal 2002.

Liquidity and Capital Resources

At the end of Q1 fiscal 2003, we had a working capital deficit of $0.4 million and a $10.7 million credit line balance outstanding, resulting in a total of $11.6 million in net debt. Funds flow from operations for Q1 fiscal 2003 amounted to $2.7 million. For purposes of approximating the number of years it would take to repay the net debt, the $2.7 million in funds flow for Q1 fiscal 2003 has been ‘annualized’ by multiplying four times, once for each quarter of the year. On that basis, the net debt years-to-repay ratio is 1.1:1.

For first quarter ended June 30/02 June 30/01 June 30/00
Debt and future items, to funds flow
(Years-to-repay ratios) Total % Chg Total % Chg Total
Funds flow from operations –
   this quarter 2,655 12 3,010 21 2,485
Funds flow from operations –
   annualized (x 4) 10,620 12 12,040 21 9,940
Long-term debt & working capital (11,625 ) 21 (14,709 ) (628 ) (2,787 )
Years to repay net debt (estimated) 1.1:1 1.2:1 0.3:1

During Q1 fiscal 2003, we did not repurchase and cancel any common shares under pursuant to our normal course issuer bid that commencing May 1, 2002 and terminating March 31, 2003 or earlier. Also during Q1 fiscal 2003, we did not undertake any derivative or hedging activities.

Capital Expenditures

During Q1 fiscal 2003, our capital expenditures decreased by $16.6 million or 97%, to $0.6 million from Q1 fiscal 2002. Of our total capital expenditures in Q1 fiscal 2003, we incurred 83% for drilling and facilities at St. Albert while we spent the balance at Halkirk and Orion, B.C. In Q1 fiscal 2002, we spent $14.5 million for an additional interest at St. Albert, while the balance of $2.6 million was spent on our properties at Halkirk and Peavey/Morinville.

For first quarter ended June 30/02 June 30/01 June 30/00
Capital expenditures Total % Chg Total % Chg Total
Drilling, completions and tie-ins 322 (82 ) 1,791 250 511
Facilities 145 (73 ) 541 32 409
Land acquisitions 48 (79 ) 227 328 53
Furniture, fixtures and computer 36 (52 ) 75 400 15
551 (79 ) 2,634 167 988
Property acquisition – St. Albert – – 14,548 – –
Total 551 (97 ) 17,182 1,639 988

Forward Looking Statements

Certain statements in this Quarterly Report constitute “forward-looking statements” within the meaning of the United States Private Securities Litigation Reform Act of 1995, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our worldwide website or otherwise, in the future, by or on our behalf. Such statements are generally identifiable by the words used such as “plan”, “expect”, “estimate”, “budget”, “anticipate”, “believe” or other similar words.

The forward-looking statements are subject to known and unknown risks and uncertainties and other factors which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: market prices for natural gas, natural gas liquids and oil products; the ability to produce and transport natural gas, natural gas liquids and oil; the results of exploration and development drilling and related activities; economic conditions in the countries and provinces in which we carry on business, especially economic slowdown; actions by governmental authorities including increases in taxes, changes in environmental and other regulations, and renegotiations of contracts; political uncertainty, including actions by insurgent groups or other conflict and the negotiation and closing of material contracts. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors; our course of action would depend upon its assessment of the future considering all information then available. In that regard, any statements as to future natural gas, natural gas liquids or oil production levels; capital expenditures; the allocation of capital expenditures to exploration and development activities; sources of funding for our capital program; drilling of new wells; demand for natural gas, natural gas liquids and oil products; expenditures and allowances relating to environmental matters; dates by which certain areas will be developed or will come on-stream; expected finding and development costs; future production rates; ultimate recoverability of reserves; dates by which transactions are expected to close; cash flows; uses of cash flows; collectibility of receivables; availability of trade credit; expected operating costs; expenditures and allowances relating to environmental matters; debt levels and changes in any of the foregoing are forward-looking statements, and there can be no assurance that the expectations conveyed by such forward-looking statements will, in fact, be realized. Readers should also refer to the other risk and uncertainty factors detailed from time to time in our Annual Report on Form 20-F filed with the U.S. Securities and Exchange Commission, last filed on August 15, 2002.

Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity, achievements or financial condition. We wish to caution readers not to place undue reliance on any forward-looking statement and to recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We assume no obligation to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements.

August 30, 2002

Fiscal 2003, Q1 Financial Highlights

Dynamic Oil & Gas, Inc. is pleased to report financial and operational highlights for the first quarter ended June 30, 2002 (“Q1”), compared with the same period of the previous two years.


(Unless otherwise indicated, $(000’s) First Quarter Ended June 30 (unaudited)
Statements of Operations 2002   % Chg   2001   % Chg   2000
Gross revenue 7,194   8   6,649   32   5,021
Funds flow from operations 2,655   (12 ) 3,010   21   2,485
   - per share, basic ($) 0.13   (13 ) 0.15   15   0.13
   - per share, diluted ($) 0.13   (7 ) 0.14   17   0.12
EBITDA 2,849   57   1,814   (19 ) 2,233
   - per share, basic ($) 0.14   56   0.09   (18 ) 0.11
   - per share, diluted ($) 0.14   75   0.08   (20 ) 0.10
Earnings 824   27   649   (40 ) 1,077
   - per share, basic ($) 0.04   33   0.03   (40 ) 0.05
   - per share, diluted ($) 0.04   33   0.03   (40 ) 0.05
Capital expenditures 551   (97 ) 17,182   1639   988
                   
Daily production                  
  Natural gas (mcf/d) 14,656   39   10,554   (7 ) 11,367
   Natural gas liquids (bbls/d) 709   74   408   (16 ) 484
   Oil (bbls/d) 135   322   32   (11 ) 36
   All products (boe*/d) 3,287   50   2,199   (9 ) 2,414
   Total Q1 production (mboe*) 299   50   200   (9 ) 220
                   
Weighted average sales prices                  
   Natural gas ($/mcf) 4.11   (28 ) 5.67   46   3.89
   Natural gas liquids ($/bbl) 19.00   (33 ) 28.21   23   23.02
   Oil ($/bbl) 39.38   (2 ) 40.25   3   39.16
   Equivalent ($/boe) 24.06   (27 ) 33.03   41   23.50
Field netback ($/boe) 12.80   (29 ) 18.12   42   12.74
   Equivalent ($/boe)                  
         * boe = barrels of oil equivalent (6 mcf – 1 bbl); mboe = one thousand boe.

    (audited)  
As at June 30 (unaudited) March 31  
 
Balance Sheets 2002   % Chg   2001   2002  
 
Working capital (11,625 ) 21   (14,709 ) (13,280 )
Total assets 34,081   (19 ) 42,069   37,152  
Shareholders’ equity 17,417   (16 ) 20,709   16,593  
Common shares, (000’s) authorized 60 million                
   - basic 20,462   1   20,217   20,365  
   - diluted 20,471   (5 ) 21,541   20,467  
   - period end 20,462   -   20,375   20,462  
 

Our funds flow from operations for Q1 fiscal 2003 was $2.7 million while our earnings were $0.8 million. Weighted average prices for natural gas and crude oil contributed solidly to our financial results while weighted average prices for natural gas liquids were less supportive.

During the quarter, the Carbondale Gas Plant (“Carbondale”) owned by Atco Midstream Ltd. was shut down for approximately two weeks for annual plant maintenance. We process a significant portion of natural gas and natural gas liquids production from our St. Albert field in Alberta through the Carbondale Plant. Including the Carbondale Plant shut-down, production averaged 3,287 boe per day throughout the quarter. Had the Carbondale Plant been fully operational during the entire quarter, we estimate our daily average production for the quarter would have increased by approximately 350 boe per day.

During Q1 fiscal 2003, our capital expenditures were $0.5 million, most of which were spent on drilling and developing our interests at St. Albert. Also, during the quarter, our financial capacity remained strong. Funds generated from operations were used to repay our existing bank credit facility and finance our capital investment program. At June 30, 2002, of the $21.0 million available to us through our revolving, demand credit facility, we had an unused balance of $10.3 million. As we progress with our fiscal 2003 capital expenditures and exploration expense budget of $18.1 million, we expect to employ a significant portion of the unused balance.

On August 19, 2002, we electronically filed our 20-F Annual Report for the fiscal year ended March 31, 2002 on SEDAR and EDGAR. Hard copies are available upon request.

Dynamic Oil & Gas, Inc. is a Canadian based energy company engaged in the production and exploration of Western Canada’s na tural 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 RELATING TO THE ESTIMATE OF FOREGONE PRODUCTION DUE TO THE CARBONDALE GAS PLANT MAINTENANCE SHUT-DOWN AND THE EXPECTATION OF CAPITAL SPENDING AND CREDIT LINE USAGE FOR THE BALANCE OF FISCAL 2003. FORWARD-LOOKING STATEMENTS INVOLVE RISKS AND UNCERTAINTIES, INCLUDING A RISK THAT THIRD-PARTY GAS PLANT MAINTENANCE SHUT-DOWNS COULD BE MORE FREQUENT THAN ONCE ANNUALLY, AND THE OTHER RISKS DETAILED FROM TIME TO TIME IN THE COMPANY'S ANNUAL REPORT ON FORM 20F FILED WITH THE U.S. SECURITIES AND EXCHANGE COMMISSION, LAST FILED ON AUGUST 19, 2002."

September 16, 2002

Dynamic Announces St. Albert Oil Well.

Dynamic Oil & Gas, Inc. is pleased to announce test results from recent drilling operations at St. Albert, Alberta.

Using slant hole drilling techniques, the Company re-entered an existing well bore at 6-25 to test a seismically identified high on the Leduc reef formation in the Big Lake Leduc ‘A’ Pool, 5 kilometers northwest of Edmonton.

During an 8 hour production test, the well flowed at an average rate of 990 barrels per day of 38 API oil, 350,000 cubic feet of gas per day and 60 barrels of NGLs per MMcf with a water cut less than 1%. Calculated AOF (Absolute Open Flow) rate on pump is 2,502 BOPD at an initial reservoir pressure of 9,848 kPa.

Dynamic expects to tie the well into it’s existing St. Albert production facility in the coming few weeks.

Dynamic (75%) and partners, Energy North Inc. (12.5%) and Trioco Resources Inc. (12.5%) farmed into Omax Resources Limited, owners of the Leduc rights in the spacing unit. Omax retains a gross production royalty of 5% to 15% on oil and 15% on gas. Dynamic and partners own the remaining mineral rights in the unit. Additional potential identified by the well bore in the oil bearing Nisku formation has yet to be evaluated.

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 significant working interests in several Central Alberta producing properties, and in two sizeable exploratory properties located in southwestern and northeastern British Columbia.

On Behalf of the Board of Directors,

Wayne J. Babcock
President and Chief Executive Officer

"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 THE ESTIMATE OF EXPECTED TIME TO TIE-IN THE WELL INTO IT’S EXISTING PRODUCTION FACILITY, AND WHETHER OR NOT THE COMPANY WILL EVALUATE THE NISKU FORMATION. FORWARD-LOOKING STATEMENTS INVOLVE RISKS AND UNCERTAINTIES, INCLUDING A RISK THAT THIRD-PARTY GAS PLANT MAINTENANCE SHUT-DOWNS COULD BE MORE FREQUENT THAN ONCE ANNUALLY, AND THE OTHER RISKS DETAILED FROM TIME TO TIME IN THE COMPANY'S ANNUAL REPORT ON FORM 20F FILED WITH THE U.S. SECURITIES AND EXCHANGE COMMISSION, LAST FILED ON AUGUST 19, 2002."