File No. 0-17551
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 6-K
Report of Foreign Issuer
Pursuant to Rule 13a-16 or 15d-16
Of the Securities Exchange Act of 1934
For the Period of Mar 31, 2003
DYNAMIC OIL & GAS, INC.
(Registrant’s name)
Airport Executive Park
#205, 10711 Cambie Road
Richmond, B.C.
Canada V6X 3G5
(Address of principal executive offices)
Indicate by check mark whether the Registrant files or will file annual reports under cover of Form 20F or Form 40-F
| Form 20-F _X_ | Form 40-F ___ |
Indicate by check mark whether the Registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934
| Yes ___ | No _X_ |
If “Yes” is marked, indicate below the file number assigned to the Registrant in connection with Rule 12g3-2(b): Not applicable.
Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| Dynamic Oil & Gas, Inc | |
| (Registrant) | |
| Dated: 05-30-03 | By: /s/ Mike Bardell |
| Mike Bardell, Chief Financial Officer & | |
| Corporate Secretary |
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| CORPORATE INFORMATION | ||
Suite 230 – 10991 Shellbridge Way Directors Officers | Stock Transfer Agent Bank Lawyers Auditors Trading Symbols |
1ST QUARTER INTERIM HIGHLIGHTS For the three months ended March 31, 2003 In this quarter and compared to the same calendar quarter last year, we: | |
| • | Increased our gross revenues by 117% to $14.3 million – a quarterly historical record; |
| • | Increased cash flow from operations(1)by 220% to $6.6 million – our second-highest quarterly record; |
| • | Increased our daily average crude oil production volume by 491% to 756 barrels per day; |
| • | Increased our earnings by 296% to $3.3 million – a quarterly historical record; |
| • | Realized a weighted average price for natural gas of $8.09 per mcf – our highest on record; |
| • | Realized a weighted average price for natural gas liquids of $33.28 per barrel – our highest on record; and |
| • | Realized a weighted average price for crude oil of $49.58 per barrel – our second-highest on record. |
| Also during this quarter and compared to the same calendar quarter last year, our: | |
| • | Daily average production of natural gas and natural gas liquids decreased by 26% or 947 barrels of oil equivalent; and |
| • | Net debt to cash flow ratio on an annualized basis, decreased to 0.6:1 from 1.0:1. At the close of this quarter, we: |
| • | Achieved targeted spending levels of $6.2 million for capital and exploration expense spending which represented 23% of our $26.5 million total budget; and |
| • | Remained on track toward achieving our December 2003 estimated daily average exit production rate of 5,200 boe per day, an increase of 51% over our 2003-Q1 daily average production rate. |
| (1) | See our Management’s Discussion and Analysis of Financial Condition and Results of Operations for a definition of "cash flow from operations”. |
| ABBREVIATIONS | |
| bbl or bbls | barrel or barrels |
| mcf | thousand cubic feet |
| bbl/d | barrels per day |
| mcf/d | thousand cubic feet per day |
| mbbl | thousand barrels |
| mmcf | million cubic feet |
| boe | barrels of oil equivalent (6 mcf = 1 bbl) |
| mmcf/d | million cubic feet per day |
| boe/d | barrels of oil equivalent per day |
| NGL’s | natural gas liquids |
| mboe | thousand barrels of oil equivalent |
| 1 |  | 1st Quarter Interim Report as of March 31, 2003 |
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following should be read in conjunction with the Financial Statements and the Notes to the Financial Statements included in this interim report. The Financial Statements have been prepared in accordance with Canadian generally accepted accounting principes (GAAP).
Unless otherwise noted, tabular amounts are in thousands of Canadian dollars, and sales volumes, production volumes and reserves are before royalties. We have presented our working interest before royalties, as we measure our performance on this basis consistent with other Canadian oil and gas companies.
In 2002, we changed our year end to December 31 from March 31. The nine-month period from April 1, 2002 to December 31, 2002 represented our fiscal transition year. As a result of the change, our new first quarter interim covers the three-month period ended March 31, 2003 (“2003-Q1”). This new interim quarter compares on a calendar basis to our previous fourth quarter interim period ended March 31, 2002, that for ease of reading we refer to as “2002-Q1”.
Where useful for comparison purposes, annualized numbers are presented by applying the three-month numbers multiplied by four. However, this method does not reflect actual results for the nine-month extrapolated period and such results may differ from the result achieved by this calculation.
HIGHLIGHTS
Operational Highlights
The following table shows certain of our key operations measures for the comparative periods presented.(Units as stated)
| For the three months ended March 31 | 2003–Q1 | 2002–Q1 | Change | % Chg | ||||
 | | | | | | | | |
| Daily production – all products (boe/d)(1) | 3,437 | 3,756 | (319 | ) | (8 | ) | ||
| Total production (mboe)(2) | 309 | 338 | (29 | ) | (9 | ) | ||
| Gas weighting (%) | 59 | 74 | (15 | ) | (20 | ) | ||
| | | | | | | | |
| (1) | Production includes our working interest before royalties. We have presented our working interest before royalties, as we measure our performance on this basis consistent with other Canadian oil and gas companies. |
| (2) | boe = barrels of oil equivalent (6 mcf = 1 bbl); mboe = one thousand boe. |
Financial Highlights
The following table shows certain of our key financial measures for the periods presented.(Units as stated)
| For the three months ended March 31 | 2003-Q1 | 2002-Q1 | Change | % Chg | ||||
| | | | | | | | |
| Net earnings (loss) | 3,322 | (1,691 | ) | 5,013 | 296 | |||
| Earnings per share | 0.16 | (0.08 | ) | 0.24 | 300 | |||
| Cash flow from operations(1) | 6,592 | 2,058 | 4,537 | 220 | ||||
| Cash flow from operations per share(1) | 0.32 | 0.10 | 0.22 | 220 | ||||
| Capital expenditures | 5,262 | 1,376 | 3,886 | 282 | ||||
| Net Debt(2) | 16,189 | 13,281 | 2,908 | 22 | ||||
| Net Debt to cash flow annualized (times)(3) | 0.6:1 | 1.0:1 | 0.4:1 | 40 | ||||
| | | | | | | | |
| (1) | Cash flow from operations is a non-GAAP measure that does not have standardized meaning as prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other companies. We consider it a key measure as it demonstrates our ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. |
| ($ 000’s) | 2003-Q1 | 2002-Q1 | Change | % Chg | |||||
| | | | | | | | | |
| Cash provided by operating activities (GAAP) | 5,550 | 3,759 | 1,791 | 48 | |||||
| Changes in non-cash working capital affecting operating (GAAP ) | 1,042 | (1,701 | ) | 2,743 | 161 | ||||
| | | | | | | | | |
| Cash flow from operations (non-GAAP) | 6,592 | 2,058 | 4,537 | 220 | |||||
| | | | | | | | |
| (2) | Net Debt is working capital, as we do not have any long-term debt. |
| (3) | Net Debt divided by cash flow from operations annualized. |
2
CAPITAL EXPENDITURES
We follow the successful efforts method of accounting for our natural gas and crude oil activities. The results from drilling can take considerable time to analyze and when it is determined that drilling has been unsuccessful in establishing commercial reserves, the costs of drilling are written off immediately and reported as exploration expenses on our Statements of Operations and Deficit. (see the section entitled, Exploration Expenses for analysis and discussion). All other capital expenditures are reported as natural gas and oil interests on our Balance Sheets.
The following table shows our capital expenditures for the periods presented.
($ 000’s)| For the three months ended March 31 | 2003-Q1 | 2002-Q1 | Change | % Chg | ||||
| | | | | | | | |
| Drilling, completions and equipping | 2,037 | (313 | ) | 2,350 | 751 | |||
| Facilities and pipelining | 375 | 193 | 182 | 94 | ||||
| Land acquisitions | 2,824 | 1,481 | 1,343 | 91 | ||||
| Corporate office | 26 | 15 | 11 | 73 | ||||
| | | | | | | | |
| Total | 5,262 | 1,376 | 3,886 | 282 | ||||
| | | | | | | | |
2003-Q1
We invested $5.3 million, a 282% increase from the amount invested in 2002-Q1 as follows:
- 10% in Alberta development properties to maintain and grow existing production levels; and
- 90% in British Columbia exploration properties for longer-term production growth.
More specifically, our capital was invested as follows:
- Alberta
- Exploratory – drilling, completions and equipping totalled $0.1 million, most of which was spent at St. Albert; and
- Development of core properties – drilling, completions and equipping totalled $0.5 million, most of which was spent at St. Albert;
- British Columbia
- Exploratory – drilling, completions and equipping totaled $1.3 million, 54% of which was spent at Orion and the balance at Cypress/Chowade;
- Development – drilling and completions totaled $0.6 million, all of which was spent at Cypress/Chowade; and
- Land – acquisitions totalled $2.8 million, 77% of which was spent at Cypress/Chowade and 23% at Orion.
2002-Q1
We invested our capital as follows:
- Alberta
- Exploratory – drilling and completion costs decreased by a net of $(0.3) million. This decrease was the net result of an increase of $0.5 million spent at Alexander and St. Albert, offset by a decrease of $0.8 million at Peavey/Morinville. The decrease at Peavey/Morinville was due to the recognition in the period of unsuccessful drilling attempts; and
- Land – acquisitions totalled $1.5 million, most of which related to the acquisition of additional working interests at St. Albert.
- British Columbia
- Development – completion costs at Orion totaled $0.2 million.
| 3 | | 1st Quarter Interim Report as of March 31, 2003 |
FINANCIAL RESULTS
Cash Flow from Operations and Earnings
2003-Q1 vs 2002-Q1
Cash flow from operations increased by a net $4.5 million or 220%, to $6.6 million mainly due to the following factors:
- A decrease of $1.1 million due to decreases in production of natural gas and natural gas liquids by 26% and 23%, respectively;
- An increase of $1.1 million due to a 490% increase in crude oil production;
- An increase of $7.6 million due to a 138% aggregate increase in weighted average commodity prices;
- A decrease of $1.4 million due mainly to a 64% increase in royalties expense; and
- A decrease of $1.7 million due to an increase in current income tax expense.
Earnings increased by a net $5.0 million or 296%, to $3.3 million mainly due to the following factors:
- A net increase of $4.5 million due to the same factors affecting our cash flow from operations as above;
- An increase of $0.5 million due to a decrease in amortization and depletion expense;
- An increase of $1.0 million due to a decrease in exploration expenses; and
- A decrease of $1.0 million due to an increase in future income tax expense.
Revenue
2003-Q1 vs 2002-Q1
Revenues increased by $7.7 million or 117%, to $14.3 million. The following table shows the price-volume variances between the two comparative periods.
Revenue Variances| ($ 000’s) | Price | Volume | Total | |||
| | | | | | |
| Natural gas | 5,816 | (833 | ) | 4,983 | ||
| Natural gas liquids | 1,053 | (269 | ) | 784 | ||
| Crude oil | 763 | 1,171 | 1,934 | |||
| | | | | | |
| Total | 7,632 | 69 | 7,701 | |||
| | | | | | |
Daily Average Production Rates and Annual Production
The following table shows our daily production rates, total production and our gas weighting as a percentage of total production.
(Units as stated)| For the three months ended March 31 | 2003-Q1 | 2002-Q1 | Change | % Chg | ||||
| | | | | | | | |
| Daily average production rates(1) | ||||||||
| Natural gas (mcf/d) | 12,249 | 16,730 | (4,481 | ) | (27 | ) | ||
| Natural gas liquids (bbls/d) | 639 | 840 | (201 | ) | (24 | ) | ||
| Crude oil (bbls/b) | 756 | 128 | 628 | 491 | ||||
| All products (boe/d)(2) | 3,437 | 3,756 | (319 | ) | (8 | ) | ||
| | | | | | | | |
| Total production (mboe/d)(2) | 309 | 338 | (29 | ) | (9 | ) | ||
| | | | | | | | |
| (1) | Daily average production rates include our working interest before royalties. We have presented our working interest before royalties, as we measure our performance on this basis consistent with other Canadian oil and gas companies. |
| (2) | boe = barrels of oil equivalent (6 mcf = 1 bbl); mboe = one thousand boe. |
2003-Q1 vs 2002-Q1
| Corporate Production Daily average production rates | |
| • | Our total daily average production rate decreased by a net 319 boe/d or 8%, to 3,437 boe/d. Of this net decrease, natural gas decreased by 746 boe/d or 27%, to 2,042 boe/d (12,249 mcf/d), natural gas liquids decreased by 201 boe/d or 24%, to 639 boe/d, while crude oil increased by 628 boe/d or 490%, to 756 boe/d. |
| Total production | |
| • | Our total production decreased by 29 mboe or 9%, to 309 mboe. |
4
The following are discussion and variance analyses of our major fields and their individual impacts on our daily average production rates and our total production.
| St. Albert, Alberta Daily average production rates | |
| • | Natural gas and natural gas liquids rates decreased by 770 boe/d or 24%, to 2,316 boe/d (13,896 mcf/d) due mainly to natural decline in reservoir pressures; and |
| • | Crude oil increased by 628 boe/d or 491%, to 756 boe/d due to three new oil wells, one of which produced at a daily average rate of 684 boe/d net to us. |
| Total production | |
| • | Our total production decreased by 13 mboe or 4%, to 276 mboe due to the changes in our daily average production rates discussed above. |
| Halkirk, Alberta Daily average production rates | |
| • | Natural gas and natural gas liquids rates decreased by 69 boe/d or 25%, to 209 boe/d (1,254 mcf/d) due mainly to production declines. |
| Total production | |
| • | Our total production decreased by 6 mboe or 24%, to 19 mboe due to the changes in our daily average production rates discussed above. |
| Peavey/Morinville, Alberta Daily average production rates | |
| • | Natural gas rates decreased by 108 boe/d or 66%, to 76 boe/d (456 mcf/d) due mainly to production declines. |
| Total production | |
| • | Our total production decreased by 10 mboe or 59%, to 7 mboe due to the changes in our daily average production rates discussed above. |
| Other, Alberta Daily average production rates | |
| • | Natural gas rates at Alexander, Simonette, Stanmore and Westlock remained unchanged at 80 boe/d (480 mcf/d). Each of these properties is comprised of a single well. |
| Total production | |
| • | Our total production from the four properties named above remained unchanged at 7 mboe. |
| Cypress/Chowade, NE British Columbia Production status | |
| • | As at March 31, 2003 we had five standing natural gas wells, two of which are expected to be on stream next quarter and the remaining three by late 2003 or early 2004. |
Weighted Average Commodity Prices
The following table shows our weighted average commodity prices for the periods presented.(Units as stated)
| For the three months ended March 31 | 2003-Q1 | 2002-Q1 | Change | % Chg | ||||
| | | | | | | | |
| Natural gas ($/mcf) | 8.09 | 3.42 | 4.67 | 137 | ||||
| Natural gas liquids ($/bbl) | 33.28 | 14.99 | 18.29 | 122 | ||||
| Crude oil ($/bbl) | 49.58 | 33.26 | 16.32 | 49 | ||||
| | | | | | | | |
| 2003-Q1 vs 2002-Q1 | |
| • | Our weighted average prices of all commodities increased by percentage changes ranging from between 49% to 137%. During most of 2003-Q1, natural gas prices were at record levels due to cold weather and supply concerns. |
| • | Our weighted average prices of all commodities increased by percentage changes ranging from between 49% to 137%. During most of 2003-Q1, natural gas prices were at record levels due to cold weather and supply concerns. |
| • | During most of 2003-Q1, crude oil prices were strong due to geo-political uncertainties and tighter supplies. |
| • | Our natural gas liquids are 45% natural-gas based and 55% crude oil-based, therefore, natural gas liquids prices follow the respective trends. |
| 5 | | 1st Quarter Interim Report as of March 31, 2003 |
Royalties, Mineral Taxes and Alberta royalty tax credits (ARTC)
The following table shows our royalties, mineral taxes and Alberta royalty tax credits and unit royalties per boe for the periods presented.
($000’s unless otherwise stated)| For the three months ended March 31 | 2003-Q1 | 2002-Q1 | Change | % Chg | ||||
| | | | | | | | |
| Crown | 1,464 | 533 | 931 | 175 | ||||
| Freehold and overriding | 1,994 | 1,032 | 962 | 93 | ||||
| Freehold mineral taxes(1) | 375 | 89 | 286 | 321 | ||||
| Alberta royalty tax credit (ARTC) | (264 | ) | (61 | ) | (203 | ) | 333 | |
| | | | | | | | |
| Total | 3,569 | 1,593 | 1,976 | 124 | ||||
| Per boe ($) | 11.53 | 4.71 | 6.82 | 145 | ||||
| | | | | | | | |
| (1) | Based on current industry trend, we have reclassified mineral taxes from Production Costs to Royalties during Fiscal 2002. For comparison purposes, prior years have been restated in our Statement of Operations and Deficit. |
2003-Q1 vs 2002-Q1
Total royalties expense increased by $2.0 million or 124%, to $3.6 million. Unit royalties expense increased by $6.82 or 145%, to $11.53 per boe due primarily to the following:
| • | An increase of $1.68 per boe due to royalty obligations associated with production from our new 06-25 oil well at St. Albert. The production at this well is burdened by a 40% royalty, comprised of a 15% overriding and a 25% crown royalty, net of ARTC; and |
| • | An increase of $5.14 per boe due to higher commodity prices. |
Production Costs
The following table shows our production and unit costs per boe for the periods presented.($000’s unless otherwise stated)
| For the three months ended March 31 | 2003-Q1 | 2002-Q1 | Change | % Chg | ||||
| | | | | | | | |
| Production costs(1)– total | 1,597 | 2,152 | (555 | ) | (26 | ) | ||
| Per boe ($) | 5.16 | 6.37 | (1.21 | ) | (19 | ) | ||
| | | | | | | | |
| (1) | Based on current industry trend, we have reclassified mineral taxes from Production Costs to Royalties during Fiscal 2002. For comparison purposes, prior years have been restated in our Statement of Operations and Deficit. |
2003-Q1 vs 2002-Q1
Production costs decreased by $0.6 million or 26%, to $1.6 million. Unit production costs decreased by $1.21 or 19%, to $5.16 per boe mainly due to the following:
| • | A general decrease of $0.50 per boe at St. Albert and a decrease of $0.54 per boe due to the elimination of monthly processing charges related to facilities acquired just prior to 2003-Q1. The facilities were acquired pursuant to the terms of a sales and leaseback agreement; and |
| • | A decrease of $0.17 per boe due to lower unit production costs at Alexander and Peavey/Morinville. |
Amortization and Depletion Expense (A&D)
The following table shows our A&D expense and unit A&D expense per boe for the periods presented.
($000’s unless otherwise stated)| For the three months ended March 31 | 2003-Q1 | 2002-Q1 | Change | % Chg | ||||
| | | | | | | | |
| A&D before the following: | 2,160 | 2,606 | (446 | ) | (17 | ) | ||
| Future removal and site restoration provision | 41 | 101 | (60 | ) | (59 | ) | ||
| Amortization of deferred items | – | (38 | ) | 38 | 100 | |||
| Total A&D | 2,201 | 2,669 | (468 | ) | (18 | ) | ||
| | | | | | | | |
| Per boe ($) | 7.11 | 7.89 | 0.78 | (10 | ) | |||
| | | | | | | | |
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2003-Q1 vs 2002-Q1
Our total A&D decreased by $0.5 million or 17%, to $2.2 million. Unit A&D costs decreased by a net of $0.78 or 9%, to $7.11 per boe mainly due to the following reasons:
- A decrease of $4.68 per boe due to a ceiling test adjustment to Peavey/Morinville assets taken in 2002-Q1;
- An increase of $1.63 per boe due to a non-recurring depletion rate change applied in 2002-Q1 to Redwater assets;
- An increase of $1.05 per boe mostly due to added unit depletion of new oil production at St. Albert that commenced in late 2002;
- An increase of $0.82 per boe due mainly to revisions in our proved producing reserves at Halkirk, Alexander, Stanmore, and Peavey/Morinville; and
- An increase of $0.47 per boe due to amortization of newly-acquired leaseholds.
Exploration Expenses
The following table shows our exploration expenses and unit exploration expenses per boe for the periods presented.
($000’s unless otherwise stated)| For the three months ended March 31 | 2003-Q1 | 2002-Q1 | Change | % Chg | ||||
| | | | | | | | |
| Drilling(1) | 99 | 1,679 | (1,580 | ) | (94 | ) | ||
| Seismic data activity | 738 | 210 | 528 | 251 | ||||
| Other | 60 | 44 | 16 | 36 | ||||
| | | | | | | | |
| Total | 897 | 1,933 | (1,036 | ) | (54 | ) | ||
| Per boe ($) | 2.90 | 5.71 | (2.81 | ) | (49 | ) | ||
| | | | | | | | |
| (1) | We follow the successful efforts method of accounting, whereby costs of drilling an unsuccessful well are expensed when it becomes known the well did not result in a discovery of proved reserves. |
2003-Q1 vs 2002-Q1
Exploration costs decreased by $1.0 million or 54%, to $0.9 million. Unit exploration expenses decreased by a net of $2.81 or 49%, to $2.90 per boe due mainly to the following:
- A decrease of $4.65 per boe associated with costs incurred in 2002-Q1 of five unsuccessful drilling attempts at Peavey/Morinville and Quirk Creek; and
- An increase of $1.77 per boe in seismic costs at Wimborne.
Interest Expense
The following table shows our interest expense and unit interest expense per boe for the periods presented.
($000’s unless otherwise stated)| For the three months ended March 31 | 2003-Q1 | 2002-Q1 | Change | % Chg | ||||
| | | | | | | | |
| Interest expense | 139 | 129 | 10 | 8 | ||||
| Per boe ($) | 0.45 | 0.38 | 0.07 | 18 | ||||
| | | | | | | | |
2003-Q1 vs 2002-Q1
The variance between periods in our interest expense is due mainly to an increase in interest rates. Our effective interest rates in 2003-Q1 and 2002-Q1 were 5.0% and 4.0%, respectively.
General and Administrative Expenses (G&A)
The following table shows our G&A expenses and unit G&A expenses per boe for the periods presented.
($000’s unless otherwise stated)| For the three months ended March 31 | 2003-Q1 | 2002-Q1 | Change | % Chg | ||||
| | | | | | | | |
| General & administrative | 729 | 722 | 7 | 1 | ||||
| Per boe ($) | 2.35 | 2.13 | 0.22 | 10 | ||||
| | | | | | | | |
| 7 | | 1st Quarter Interim Report as of March 31, 2003 |
2003-Q1 vs 2002-Q1
G&A increased marginally to $0.7 million. Unit G&A costs increased by $0.22 or 10%, to $2.35 per boe due mainly to the following:
- An increase of $0.14 per boe due to a decrease in overhead credits that we are entitled to earn when we operate properties. In 2003-Q1, we operated fewer capital projects than in 2002-Q1; and
- An increase of $0.10 per boe in insurance premiums.
Income Tax Expense
The following table shows our current and future income tax expenses for the periods presented.
($ 000’s unless otherwise stated)
| For the three months ended March 31 | 2003-Q1 | 2002-Q1 | Change | % Chg | ||||
| | | | | | | | |
| Income tax expense (recovery)(1) | ||||||||
| Current | 1,684 | (46 | ) | 1,730 | – | |||
| Future | 171 | (854 | ) | 1,025 | 120 | |||
| | | | | | | | |
| Total | 1,855 | (900 | ) | 2,755 | 306 | |||
| | | | | | | | |
| (1) | We use the liability method of tax allocation in accounting for income taxes. Future tax assets and liabilities are determined based on differences between the financial reporting and tax bases of assets and liabilities, and measured using the substantially enacted rates and laws that will be in effect when the differences are expected to reverse. |
2003-Q1 vs 2002-Q1
Total income tax expense increased to $1.9 million from a recovery of $0.9 million. This expense was consistent with our pre-tax earnings. Our effective tax rate was 35.8% in 2003-Q1 and is in line with statutory tax rates.
LIQUIDITY AND CAPITAL RESOURCES
Our capital resources at the end of 2003-Q1 consisted of cash flow from operations and available lines of bank credit.
Our net debt decreased at the end of 2003-Q1 compared to December 31, 2002 by $0.6 million, as cash flow from operations exceeded our capital expenditures and exploration expenses.
We expect to fund our capital expenditure and exploration expense spending in fiscal 2003 from cash flow provided by operations and our revolving bank operating loan. Our working capital and net debt levels are primarily dependent upon our operating cash flows, the amount of our capital investment and the timing of incurred field activities.
Early in the next quarter ended June 30, 2003, 780,000 stock options were exercised for $1.3 million.
OUTLOOK FOR 2003
2003 Capital Expenditure and Exploration Expense Program
During 2003-Q1, we spent 22% of our fiscal capital expenditure budget of $23.7 million and 32% of our fiscal exploration expense budget of $2.8 million. There were no significant changes in our spending plans for the 2003 year.
We continue to focus on maintaining and growing our production from existing core properties and exploring for new reserves. Our drilling program for 2003 includes 20 wells, 14 of which are new and six re-entries. Of the 14 new wells, four are for development work in Alberta and seven are planned for exploratory work in northeast British Columbia.
2003 Daily Production
We expect to reach a daily production exit rate by December 31, 2003 of 5,200 boe per day, a 51% increase over our daily average production rate of 3,437 boe/d achieved in 2003-Q1. Approximately three-quarters of this increase is expected to come from increased crude oil production at St. Albert, subject to on-going regulatory processes. The balance is expected to come from natural gas at St. Albert and Cypress/Chowade.
8
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this Interim 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 behalf of us. Such statements are generally identifiable by the terminology used such as “plans“, “expects, “estimates“, “budgets“, “intends“, “anticipates“, “believes“, “projects“, “indicates“, “targets“, “objective", “could“, “may“ or other similar words.
The forward-looking statements are subject to known and unknown risks and uncertainties and other factors that 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 crude oil products; the ability to produce and transport natural gas, natural gas liquids and crude 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 our assessment of the future considering all information then available. In that regard, any statements as to future natural gas, natural gas liquids or crude 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 crude 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.
Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us 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.
| 9 | | 1st Quarter Interim Report as of March 31, 2003 |
BALANCE SHEETS
(in Canadian Dollars)| March 31 | December 31 | |||||
| 2003 | 2002 | |||||
| | | | | | |
| (unaudited) | (audited) | |||||
| Assets | ||||||
| Current | ||||||
| Accounts receivable | $ | 8,423,680 | $ | 6,426,761 | ||
| Prepaid expenses | 531,980 | 351,771 | ||||
| Income taxes receivable | – | 131,772 | ||||
| | | | | | |
| Total current assets | 8,955,660 | 6,910,304 | ||||
| | | | | | |
| Natural gas and oil interests | 39,668,891 | 36,568,076 | ||||
| Capital assets | 169,411 | 168,366 | ||||
| | | | | | |
| $ | 48,793,962 | $ | 43,646,746 | |||
| | | | | | |
| Liabilities & Shareholders’ Equity | ||||||
| Current | ||||||
| Bank indebtedness | $ | 455,638 | $ | 1,519,923 | ||
| Operating loan | 13,525,000 | 11,075,000 | ||||
| Accounts payable & accrued liabilities | 9,813,286 | 11,133,844 | ||||
| Income taxes payable | 1,350,855 | – | ||||
| | | | | | |
| Total current liabilities | 25,144,779 | 23,728,767 | ||||
| | | | | | |
| Provision for future removal and site restoration | 1,031,653 | 990,982 | ||||
| Future income tax liability | 853,200 | 682,300 | ||||
| | | | | | |
| Total liabilities | 27,029,632 | 25,402,049 | ||||
| | | | | | |
| Share capital | 20,917,884 | 20,720,629 | ||||
| Retained earnings (deficit) | 846,446 | (2,475,932 | ) | |||
| | | | | | |
| Total shareholders’ equity | 21,764,330 | 18,244,697 | ||||
| | | | | | |
| $ | 48,793,962 | $ | 43,646,746 | |||
| | | | | | |
Director |
Director |
10
STATEMENTS OF OPERATIONS AND RETAINED EARNINGS (DEFICIT)
(in Canadian Dollars)| For the three months ended March 31 | 2003 | 2002 | ||||
| | | | | | |
| (unaudited) | (unaudited) | |||||
| Revenue | ||||||
| Natural gas, liquids and oil sales | $ | 14,308,409 | $ | 6,607,723 | ||
| Royalties | (3,832,814 | ) | (1,654,341 | ) | ||
| Production costs | (1,596,568 | ) | (2,152,107 | ) | ||
| | | | | | |
| 8,879,027 | 2,801,275 | |||||
| Alberta royalty tax credit | 263,993 | 61,492 | ||||
| | | | | | |
| 9,143,020 | 2,862,767 | |||||
| | | | | | |
| Expenses | ||||||
| General and adminstrative (schedule 1) | 728,523 | 721,565 | ||||
| Interest expense on operating loan | 139,345 | 129,425 | ||||
| Interest income | (190 | ) | – | |||
| | | | | | |
| 867,678 | 850,990 | |||||
| | | | | | |
| Earnings from operations before the following: | 8,275,342 | 2,011,777 | ||||
| Amortization and depletion (schedule 2) | 2,201,003 | 2,668,850 | ||||
| Exploration expenses (schedule 3) | 897,287 | 1,933,006 | ||||
| Loss on sale of natural gas and oil interests | – | 352 | ||||
| | | | | | |
| Earnings (loss) before taxes | 5,177,052 | (2,590,431 | ) | |||
| | | | | | |
| Current tax expense (recovery) | ||||||
| – Current | 1,683,774 | (45,913 | ) | |||
| – Future | 170,900 | (854,000 | ) | |||
| | | | | | |
| Net earnings (loss) | 3,322,378 | (1,690,518 | ) | |||
| | | | | | |
| Deficit, beginning of period | (2,475,932 | ) | (2,547,470 | ) | ||
| Premium on purchase and cancellation of common shares | – | (83,551 | ) | |||
| | | | | | |
| Retained earnings (deficit), end of period | $ | 846,446 | $ | (4,321,539 | ) | |
| | | | | | |
| Earnings per share | ||||||
| basic | $ | 0.16 | $ | (0.08 | ) | |
| diluted | $ | 0.16 | $ | (0.08 | ) | |
| | | | | | |
| 11 | | 1st Quarter Interim Report as of March 31, 2003 |
STATEMENTS OF CASH FLOWS
(in Canadian Dollars)| For the three months ended March 31 | 2003 | 2002 | ||||
| | | | | | |
| (unaudited) | (unaudited) | |||||
| Operating activities | ||||||
| Earnings | $ | 3,322,378 | $ | (1,690,518 | ) | |
| Add (deduct) items not involving cash: | ||||||
| Amortization and depletion | 2,201,003 | 2,668,850 | ||||
| Future income taxes | 170,900 | (854,000 | ) | |||
| Exploration expenses | 897,287 | 1,933,006 | ||||
| Gain (loss) on sale of natural gas and oil interests | – | 352 | ||||
| | | | | | |
| Cash flow from operations | 6,591,568 | 2,057,690 | ||||
| Changes in non-cash working capital | ||||||
| affecting operating activities | (1,041,790 | ) | 1,701,150 | |||
| | | | | | |
| Cash provided by operating activities | 5,549,778 | 3,758,840 | ||||
| | | | | | |
| Financing activities | ||||||
| Bank indebtedness | (1,064,285 | ) | 842,812 | |||
| Operating loan | 2,450,000 | (1,950,000 | ) | |||
| Shares issued for cash | 197,255 | 325,120 | ||||
| Share repurchases | – | (225,623 | ) | |||
| | | | | | |
| Cash provided by (used in) financing activities | 1,582,970 | (1,007,691 | ) | |||
| | | | | | |
| Investing activities | ||||||
| Purchase of capital assets | (26,398 | ) | (14,810 | ) | ||
| Natural gas and oil interests | (5,235,794 | ) | (1,361,611 | ) | ||
| Exploration expenses | (897,287 | ) | (1,933,006 | ) | ||
| Proceeds on sale of natural gas and oil interests | – | (352 | ) | |||
| Changes in non-cash working capital | ||||||
| affecting investing activities | (973,269 | ) | 541,737 | |||
| | | | | | |
| Cash used in investing activities | (7,132,748 | ) | (2,768,042 | ) | ||
| | | | | | |
| (Decrease) increase in cash and cash equivalents | – | (16,893 | ) | |||
| Cash and cash equivalents, beginning of period | – | 16,893 | ||||
| | | | | | |
| Cash and cash equivalents, end of period | $ | – | $ | – | ||
| | | | | | |
| Supplemental disclosures of cash flow information | ||||||
| Cash paid during the period for: | ||||||
| Interest | $ | 146,612 | $ | 147,265 | ||
| Income taxes | $ | 201,147 | $ | 94,694 | ||
| | | | | | |
12
NOTES TO UNAUDITED FINANCIAL STATEMENTS
Note 1. Basis of Presentation and Summary of Significant Accounting Policies
The accompanying interim financial statements have been prepared in accordance with Canadian generally accepted accounting principles for interim financial information and accordingly do not include all disclosures required for annual financial statements.
In the opinion of management, all adjustments (consisting of normal recurring accruals) considered for a fair presentation have been included. Operating results for the three-month period ended March 31, 2003 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2003.
During 2002, Dynamic Oil & Gas, Inc. (“the Company”) changed its year end to December 31 from March 31. Accordingly, the Company filed with the Securities Commissions, its nine-month Annual Report (“Transition Report”) covering the period April 1, 2002 to December 31, 2002.
These statements should be read in conjunction with the audited nine-month financial statements included in the Transition Report. These financial statements reflect the same significant accounting policies as those described in the notes to financial statements included in the Transition Report, except for the change in accounting policy outlined in Note 2 below.
Note 2. Change in Accounting Policies
Stock-Based Compensation
Prior to the adoption of CICA 3870 effective April 1, 2002, no compensation expense was recognized under Canadian GAAP when stock options were issued to directors, employees or consultants. 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 (but not required) 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 the Company accounts for stock-based payments to non-employees using the fair value method, it has elected to continue to use the intrinsic value method of accounting for stock options granted to employees and directors under its stock option plan. The Company has disclosed the required pro forma effect on earnings and earnings per share as if the fair value method of accounting as prescribed in CICA 3870 had been applied (see Note 4).
Note 3. Common Share Capital
a) Issued and Outstanding Shares
The following table sets forth the issued and outstanding common shares:| For the three months ended March 31 | 2003 | 2002 | ||||||
| | | | | | | | |
| # | $ | # | $ | |||||
| | | | | | | | |
| Outstanding, beginning of the period | 20,272,530 | 20,720,696 | 20,347,230 | 20,731,474 | ||||
| Shares issued for cash: | ||||||||
| Stock options exercised | 113,666 | 197,255 | 254,000 | 325,120 | ||||
| Share repurchases and cancellations | (139,000 | ) | (140,072 | ) | ||||
| Outstanding, end of period | 20,386,196 | 20,917,884 | 20,462,230 | 20,914,522 | ||||
| | | | | | | | |
| 13 | | 1st Quarter Interim Report as of March 31, 2003 |
b) Earnings per Share
The following table sets forth the computation of basic and diluted earnings per share:
| For the three months ended March 31 | 2003 | 2002 | ||
| | | | |
| Numerator: | ||||
| Net earnings (loss) per period | 3,322,378 | (1,690,518 | ) | |
| | | | |
| Denominator: | ||||
| Weighted average number of | ||||
| common shares outstanding | 20,315,307 | 20,365,031 | ||
| Effect of dilutive stock options | 916,839 | 155,519 | ||
| | | | |
| Basic earnings (loss) per share | 0.16 | (0.08 | ) | |
| Diluted earnings (loss) per share | 0.16 | (0.08 | ) | |
| | | | |
c) Options Outstanding
The following summarizes the status of the Company’s stock option plan for the periods presented.
| Weighted | ||||
| Number | Average | |||
| of Shares | Option Price | |||
| (#) | ($) | |||
| | | | |
| Outstanding at December 31, 2002 | 2,077,750 | 1.83 | ||
| Granted | – | – | ||
| Exercised | 113,666 | 1.74 | ||
| Outstanding at March 31, 2003 | 1,990,750 | 1.87 | ||
| Options exercisable at March 31, 2003 | 1,637,083 | 1.85 | ||
| | | | |
Options outstanding as at March 31, 2003 had expiry dates ranging from April 22, 2003 to December 17, 2012.
Note 4. Stock-Based Compensation
Had the Company recognized compensation costs for its stock option grants consistent with the methods recommended by CICA 3870 (see Note 2 – Stock-Based Compensation), the Company’s net earnings and earnings per share would have been stated at the pro forma amounts shown in the table below.
| For the three months ended March 31 | 2003 | 2002 | ||
| | | | |
| Net earnings (loss): | ||||
| As reported | 3,322,378 | (1,690,518 | ) | |
| Pro forma | 3,291,944 | (1,698,418 | ) | |
| Basic earnings per common share: | ||||
| As reported | 0.16 | 0.08 | ||
| Pro forma | 0.16 | 0.08 | ||
| Diluted earnings per common share: | ||||
| As reported | 0.16 | 0.08 | ||
| Pro forma | 0.16 | 0.08 | ||
| | | | |
The fair values of the stock option grants were estimated based on the dates of grant using the Black-Scholes option-pricing model with the following assumptions: risk-free average interest rate of 5%; dividend yield of 0%; estimated volatility of 57%; and estimated lives of 3 years.
14
SCHEDULE 1: GENERAL AND ADMINISTRATIVE
| For the three months ended March 31 | 2003 | 2002 | ||||
| | | | | | |
| (unaudited) | (unaudited) | |||||
| Advertising and promotion | $ | 46,404 | $ | 88,712 | ||
| Insurance | 43,871 | 13,648 | ||||
| Interest | 10,863 | 17,839 | ||||
| Office and printing | 151,616 | 120,086 | ||||
| Professional fees | 168,646 | 143,962 | ||||
| Provincial capital taxes | – | 8,918 | ||||
| Regulatory and other fees | 16,098 | 12,818 | ||||
| Rent | 18,723 | 23,174 | ||||
| Salaries and benefits | 313,577 | 392,072 | ||||
| Telephone | 5,575 | 3,944 | ||||
| Travel | 15,840 | 3,793 | ||||
| Cost recoveries | (62,690 | ) | (107,401 | ) | ||
| | | | | | |
| $ | 728,523 | $ | 721,565 | |||
| | | | | | |
SCHEDULE 2: AMORTIZATION AND DEPLETION
| For the three months ended March 31 | 2003 | 2002 | ||||
| | | | | | |
| (unaudited) | (unaudited) | |||||
| Amortization and depletion | $ | 2,160,332 | $ | 2,605,947 | ||
| Future removal, site restoration | 40,671 | 100,960 | ||||
| Amortization, deferred gain on sale | – | (38,057 | ) | |||
| | | | | | |
| $ | 2,201,003 | $ | 2,668,850 | |||
| | | | | | |
SCHEDULE 3: EXPLORATION EXPENSES
| For the three months ended March 31 | 2003 | 2002 | ||||
| | | | | | |
| (unaudited) | (unaudited) | |||||
| Drilling | $ | 99,327 | $ | 1,678,579 | ||
| Seismic data activity | 737,856 | 210,145 | ||||
| Non-producing lease rentals | 53,679 | 29,904 | ||||
| Property investigations | 6,425 | 14,378 | ||||
| | | | | | |
| $ | 897,287 | $ | 1,933,006 | |||
| | | | | | |
STATEMENT OF EXECUTIVE REMUNERATION
During 2003-Q1, we did not pay any cash compensation to its directors, in their capacities as such. We paid salaries to five executive officers and royalties pursuant to agreements with three of those executive officers. The salaries and royalties paid in 2003-Q1 and 2002-Q1 totaled $463,170 and $351,477, respectively.
| 15 | | 1st Quarter Interim Report as of March 31, 2003 |