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 Directors Officers Stock Transfer Agent Bank Lawyers Accountants Trading Symbols NASDAQ:DYOLF
|
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. |
(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 OFOPERATIONS 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 "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 "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." |
