2ND QUARTER REPORT
AS OF JUNE 30, 2003
| CORPORATE INFORMATION | |
| | |
| Suite 230 – 10991 Shellbridge Way | Stock Transfer Agent |
| Richmond, British Columbia Canada V6X 3C6 | CIBC Mellon Trust Company |
| Tel: 604/214-0550 Toll free: 1-800/663-8072 | 1600 – 1066 W. Hastings St. |
| Fax: 604/214-0551 | Vancouver, BC Canada V6E 3X1 |
| E-mail: infodynamic@dynamicoil.com | |
| Website: www.dynamicoil.com | Bank |
| Regulatory filings website: www.sedar.com | National Bank of Canada |
| | 407 Eighth Avenue S.W. |
| Directors | Calgary, AB Canada T2P 1E5 |
| Wayne J. Babcock | |
| John A. Greig | Lawyers |
| David J. Jennings | Irwin, White & Jennings |
| John Lagadin | 2620 – 1055 W. Georgia St. |
| Jonathan A. Rubenstein | Vancouver, BC Canada V6E 3R5 |
| William B. Thompson | Perkins Coie LLP |
| Donald K. Umbach | 6th Floor – 1620 26th St. |
| | Santa Monica, CA, USA 90404 |
| Officers | |
| Wayne J. Babcock,President & CEO | Auditors |
| Donald K. Umbach,Vice President & COO | Ernst & Young LLP |
| James R. Britton,Vice President, Exploration | 700 West Georgia Street |
| David G. Grohs,Vice President, Production | Vancouver, BC Canada V7Y 1C7 |
| Michael A. Bardell,CFO & Corporate Secretary | |
| | Trading Symbols |
| | TSX: DOL |
| | NASDAQ: DYOLF |
2ND QUARTER INTERIM HIGHLIGHTS
For the three months ended June 30, 2003
In the last few days of this quarter, we:
- Achieved an exit rate of 4,150 boe/d. Our full-quarter average production was 3,207 boe/d; and
- Tied in the first two of our five new, standing natural gas wells at Cypress/Chowade in northeast British Columbia.
Other production measures we took in the quarter were:
- To temporarily holdback 393 boe/d to conduct scheduled, annual plant preventative maintenance and three-year, boiler inspection programs at facilities that handle our St. Albert production; and
- To increase our daily average production of natural gas and natural gas liquids by 246 boe/d, by rerouting St. Albert production into third-party compression facilities. This helped to mitigate production declines of 640 boe/d from the same quarter last year.
In this quarter and compared to the same calendar quarter last year, we:
- Increased our gross revenues by 52% to $10.9 million;
- Increased cash flow from operations by 105% to $5.4 million;
- Increased our net earnings by 79% to $1.5 million; and
- Increased our daily average oil production volume by 415% to 695 barrels per day.
Also during this quarter and compared to the same quarter last year, we realized the following increases in our weighted average prices:
- A 67% increase in natural gas to $6.87 per mcf;
- A 37% increase in natural gas liquids to $26.02 per barrel; and
- A 3% increase in crude oil to $40.70 per barrel.
At the close of this quarter, we:
- Achieved targeted spending levels of $6.4 million for capital and exploration expense spending which represented 24% of our $26.5 million 2003 budget; and
- Remained on track toward achieving our December 2003 target exit production rate of 5,200 boe/d.
| 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 |  | 2nd Quarter Interim Report as of June 30, 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 principles (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 fiscal 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. Throughout this discussion and analysis, we compare the interim results of this year against those of the same calendar period last year. For ease of reading, we may refer to the comparative periods as follows:
| Interim Periods Reported | 2003 | | 2002 | |
| April 1 to June 30, referred to as | 2003-Q2 | | 2002-Q2 | |
| January 1 to June 30, referred to as | 2003-Half | | 2002-Half | |
| January 1 – March 31, referred to as | 2003-Q1 | | 2002-Q1 | |
Where useful for comparison purposes, annualized numbers are presented by multiplying the three-month or six-month numbers by four or two, respectively. This method, however, does not reflect actual results for the applicable extrapolated periods and as such may differ from the results achieved by this calculation.
HIGHLIGHTS
Operational Highlights
The following table shows certain of our key operating measures for the comparative periods presented.
(Units as stated)| | Three Months Ended June 30 | | Six Months Ended June 30 | |
| | 2003 | | 2002 | | 2003 | | 2002 | |
| Daily average production – all products (boe/d) | 3,207 | | 3,287 | | 3,322 | | 3,520 | |
| Total production (mboe) | 292 | | 299 | | 601 | | 637 | |
| Gas weighting (%) | 60 | | 74 | | 60 | | 74 | |
Financial Highlights
The following table shows certain of our key financial measures for the comparative periods presented.
($ 000’s unless otherwise stated)| | Three Months Ended June 30 | | Six Months Ended June 30 | |
| | 2003 | | 2002 | | 2003 | | 2002 | |
| Net earnings (loss) | 1,472 | | 824 | | 4,794 | | (867 | ) |
| Net earnings (loss) per share ($/share) | 0.07 | | 0.04 | | 0.23 | | (0.04 | ) |
| Cash flow from operations(1) | 5,434 | | 2,655 | | 12,025 | | 4,713 | |
| Cash flow from operations per share ($/share)(1) | 0.26 | | 0.13 | | 0.58 | | 0.23 | |
| Capital expenditures | 5,590 | | 551 | | 10,852 | | 1,927 | |
| Net debt(2) | 15,902 | | 11,625 | | 15,902 | | 11,625 | |
| Net debt to cash flow annualized (times)(3) | 0.7:1 | | 1.1:1 | | 0.7:1 | | 1.2:1 | |
| (1) | Cash flow from operations is a non-GAAP measure that does not have standardized meaning as prescribed by GAAP and therefore may or may not be comparable to similar measures presented by other companies. We consider it a key measure as it demonstrates our ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt.
|
| | ($000’s) | Three Months Ended June 30 | | Six Months Ended June 30 | |
| | | 2003 | | 2002 | | 2003 | | 2002 | |
| | Cash provided by operating activities (GAAP) | 5,112 | | 3,801 | | 10,661 | | 7,560 | |
| | Changes in non-cash working capital affecting operating (GAAP) | 322 | | (1,146 | ) | 1,364 | | (2,847 | ) |
| | Cash flow from operations (non-GAAP) | 5,434 | | 2,655 | | 12,025 | | 4,713 | |
(2)
| Net debt is working capital, as we do not have any long-term debt.
|
(3)
| Net debt divided by cash flow from operations annualized. Annualized numbers are presented by multiplying the three-month or six-month numbers by four or two, respectively. This method, however, does not reflect actual results for the applicable extrapolated periods and as such may differ from the results achieved by this calculation.
|
2
CAPITAL EXPENDITURES
We follow the successful efforts method of accounting for our natural gas and crude oil activities. The results from drilling can take considerable time to analyze and when it is determined that drilling has been unsuccessful in establishing commercial reserves, the costs of drilling are written off immediately and reported as exploration expenses on our Statements of Operations and Deficit (see the section entitled, Exploration Expenses for analysis and discussion). All other capital expenditures are reported as natural gas and oil interests on our Balance Sheets.
The following table shows our capital expenditures for the comparative periods presented.
($ 000’s)| | Three Months Ended June 30 | | Six Months Ended June 30 | |
| | 2003 | | 2002 | | 2003 | | 2002 | |
| Drilling, completions and equipping | 3,675 | | 322 | | 5,712 | | 9 | |
| Facilities and pipelining | 509 | | 145 | | 883 | | 338 | |
| Land acquisitions | 1,306 | | 48 | | 4,130 | | 1,529 | |
| Corporate office | 100 | | 36 | | 127 | | 51 | |
| Total | 5,590 | | 551 | | 10,852 | | 1,927 | |
2003-Q2
We invested $5.6 million, 67% in Alberta and 23% in British Columbia as follows:
Alberta
Exploratory drilling totaled $0.5 million, most of which was spent at St. Albert and Wimborne. Development drilling, completions and equipping totaled $2.4 million, the largest part of which was spent at St. Albert. Land acquisitions totaled $1.3 million, essentially all of which was spent at Wimborne.
British Columbia
Exploratory drilling totaled $1.2 million, 98% of which was spent at Orion and the balance at Cypress/Chowade. Development drilling, completions and equipping totaled $0.1 million, most of which was spent at Cypress/Chowade.
2002-Q2
We invested our capital as follows:
Alberta
Development drilling and completions totaled $0.4 million, most of which was spent at St. Albert.
British Columbia
Land acquisitions totaled $0.1 million at Orion.
2003-Half
We invested $10.9 million, 44% in Alberta and 56% in British Columbia as follows:
Alberta
Exploratory drilling totaled $0.6 million, most of which was spent at St. Albert & Wimborne, Development drilling, completions and equipping totaled $2.9 million, the majority of which was spent at St. Albert. Land acquisitions at Wimborne totaled $1.3 million.
British Columbia
Exploratory drilling totaled $2.5 million, 75% of which was spent at Orion and the balance at Cypress/Chowade. Development drilling, completions and equipping totaled $0.7 million, most of which was spent at Cypress/Chowade. Land acquisitions totaled $2.7 million, 78% of which was spent at Cypress/Chowade and the remainder at Orion.
2002-Half
We invested $1.9 million on land acquisitions, mainly at St. Albert.
FINANCIAL RESULTS
Cash Flow from Operations and Net Earnings
2003-Q2 vs 2002-Q2
Cash flow from operations increased by a net $2.8 million or 105%, to $2.7 million mainly due to the following factors:
| 3 | | 2nd Quarter Interim Report as of June 30, 2003 |
A decrease of $2.4 million due to decreases in sales volumes of natural gas and natural gas liquids by 21% and 19%, respectively;
An increase of $2.0 million due to a 415% increase in crude oil production; and
Those involving expenses:
A net decrease of $0.9 million due mainly to a $2.1 million increase in royalties, general and administrative and interest expenses, partially offset by a recovery of $1.2 million in current income tax expense.
Net earnings increased by a net $0.7 million or 79%, to $1.5 million mainly due to the same factors affecting our cash flow from operations above and the following additional expense factors:
- A decrease of $0.5 million due to an increase in amortization and depletion expense;
- A decrease of $0.4 million due to an increase in exploration expenses; and
- A decrease of $1.2 million due to an increase in future income tax expense.
2003-Half vs 2002-Half
Cash flow from operations increased by a net of $7.3 million or 155%, to $4.7 million. This was the net result of a $12.6 million increase due to higher commodity prices; a $5.0 million decrease caused by lower volume sales of natural gas and natural gas liquids; an increase of $3.8 million as a result of higher volume sales of crude oil; and a decrease of $4.1 million due mainly to an increase in royalties expense.
Net earnings increased by a net $5.7 million or 653%, to $4.8 million. This was the net result of the same factors that affected our cash flow from operations referred to above; a $0.1 million decrease due to higher amortization and depletion expense; a $0.7 million increase due to lower exploration expenses; and a $2.2 million decrease due to higher future income tax expense.
Revenue
The following table shows our price/volume variances between the comparative periods presented.
Revenue Variances($ 000’s)| | Three Months Ended June 30, 2003 | | Six Months Ended June 30, 2003 | |
| | | | vs June 30, 2002 | | | | vs June 30, 2002 | |
| | Price- | | Volume- | | | | Price- | | Volume- | | | |
| | based | | based | | Total | | based | | based | | Total | |
| Natural gas | 3,686 | | (2,159 | ) | 1,527 | | 10,581 | | (4,071 | ) | 6,510 | |
| Natural gas liquids | 445 | | (294 | ) | 151 | | 1,805 | | (870 | ) | 935 | |
| Crude oil | 17 | | 2,034 | | 2,051 | | 216 | | 3,769 | | 3,985 | |
| Total | 4,148 | | (419 | ) | 3,729 | | 12,602 | | (1,172 | ) | 11,430 | |
2003-Q2 vs 2002-Q2
Revenues increased by $3.7 million or 52%, $4.1 million of which was due to price-based increases partially offset by $0.4 million in volume-based decreases.
2003-Half vs 2002-Half
Revenues increased by $11.4 million or 52%, $12.6 million of which was due to price-based increases partially offset by $1.2 million in volume-based decreases.
Daily Average Production Rates and Annual Production
The following table shows our daily average production rates and our total production for the comparative periods presented.
(Units as stated)| | Three Months Ended June 30 | | Six Months Ended June 30 | |
| | 2003 | | 2002 | | 2003 | | 2002 | |
| Daily average production rates | | | | | | | | |
| Natural gas (mcf/d) | 11,616 | | 14,656 | | 11,930 | | 15,687 | |
| Natural gas liquids (bbls/d) | 576 | | 709 | | 608 | | 774 | |
| Crude oil (bbls/d) | 695 | | 135 | | 726 | | 132 | |
| All products (boe/d) | 3,207 | | 3,287 | | 3,322 | | 3,520 | |
| Total production (mboe) | 292 | | 299 | | 601 | | 637 | |
2003-Q2 vs 2002-Q2
Our daily production exit rate for 2003-Q2 was 4,150 boe/d, a level that was achieved in only the last few days of June 2003.
4
Our total daily average production rate decreased by a net 80 boe/d or 2%, to 3,207 boe/d. Of this net decrease, natural gas decreased by 506 boe/d or 21%, to 1,936 boe/d (11,616 mcf/d), natural gas liquids decreased by 133 boe/d or 19%, to 576 boe/d, while crude oil increased by 560 boe/d or 415%, to 695 boe/d.
Total production decreased by a net 7 mboe or 2%, to 292 mboe.
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 (“daily rates”) of natural gas and natural liquids rates decreased by 526 boe/d or 20%, to 2,145 boe/d (12,870 mcf/d) due mainly to a natural decline in reservoir pressures. To help mitigate pressure declines, we re-routed production through third-party compression facilities at the end of 2003-Q2, thereby adding 246 boe/d to our production rates.
Daily rates of crude oil increased by 560 boe/d or 415%, to 695 boe/d due to three new oil wells that were not yet discovered in 2002-Q2.
Total production from the field increased by 3 mboe or 1%, to 258 mboe.
Halkirk, Alberta
Daily rates of natural gas and natural liquids decreased by 1 boe/d to 195 boe/d (1,170 mcf/d). Currently, we have six wells in production with a plan to drill two more next quarter.
Total production decreased marginally by 1 mboe to 18 mboe.
Peavey/Morinville, Alberta
Daily rates of natural gas decreased by 67 boe/d or 60%, to 62 boe/d (312 mcf/d) due to production declines and a 27-day interruption during 2003-Q2 to update compression facilities.
Total production decreased by 7 mboe or 58%, to 6 mboe.
Other, Alberta
We produced natural gas from four single-well fields: Alexander; Simonette; Stanmore; and Westlock. Aggregate daily rates decreased by 47 boe/d or 33% to 94 boe/d. Alexander, the main reason for the decrease, was restored to previous daily rate levels late in 2003-Q2 after a maintenance workover.
Total production decreased by 4 mboe or 33%, to 8 mboe.
Cypress/Chowade, NE British Columbia
Two previously-drilled natural gas wells commenced production for less than a week at the end of 2003-Q2. These two wells produced at a combined rate of 373 boe/d.
As at the end of 2003-Q2 we had three standing natural gas wells awaiting tie-in. These wells are expected to be on stream late in 2003.
2003-Half vs 2002-Half
Our daily rates of production decreased by a net of 198 boe/d or 6%, to 3,322 boe/d. While daily rates of natural gas and natural gas liquids from all fields decreased by 792 boe/d, daily rates of crude oil increased by 594 boe/d. The St. Albert field was responsible for 82% of the daily rate decrease in natural gas and natural gas liquids (see explanations above). St. Albert was also responsible for all of the daily rate increase in crude oil. Natural gas production from Cypress/Chowade, our newest field, commenced at the end of the 2003-Half.
Total production from all fields decreased by a net 36 mboe or 6%, to 601 mboe. While production of natural gas and natural gas liquids decreased by 143 mboe, production of crude oil increased by 107 mboe.
Weighted Average Commodity Prices
The following table shows our weighted average commodity prices for the comparative periods presented.
(Units as stated)| | Three Months Ended June 30 | | Six Months Ended June 30 | |
| | 2003 | | 2002 | | 2003 | | 2002 | |
| Natural gas ($/mcf) | 6.87 | | 4.11 | | 7.50 | | 3.75 | |
| Natural gas liquids ($/bbl) | 26.02 | | 19.00 | | 29.83 | | 16.83 | |
| Crude oil ($/bbl) | 40.70 | | 39.38 | | 45.33 | | 36.42 | |
2003-Q2 vs 2002-Q2
Our weighted average prices of natural gas increased by 67%, natural gas liquids by 37% and crude oil by 3%.
The main North American market factor that buoyed our weighted average natural gas prices was a supply shortage due to remaining low inventory levels. The primary world market factor softening our weighted average crude oil prices was diminishing geo-political uncertainties.
| 5 | | 2nd Quarter Interim Report as of June 30, 2003 |
Our natural gas liquids are 45% natural gas-based and 55% crude oil-based, therefore, natural gas liquids prices followed the respective trends mentioned above.
2003-Half vs 2002-Half
Our weighted average prices of natural gas increased by 100%, natural gas liquids by 77% and crude oil by 24%.
Hedging
We have no hedge positions, however, by varying our product sales mix of natural gas, natural gas liquids and crude oil, we manage the potential risk of single-product price volatility. Further, we vary our natural gas sales mix between AECO and NYMEX-based contracts in order to capitalize on potential favourable price spreads between the two market indices.
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 comparative periods presented.
($ 000’s unless otherwise stated)| | Three Months Ended June 30 | | Six Months Ended June 30 | |
| | 2003 | | 2002 | | 2003 | | 2002 | |
| Crown | 1,282 | | 418 | | 2,746 | | 951 | |
| Freehold and overriding | 1,816 | | 961 | | 3,810 | | 1,993 | |
| Freehold mineral taxes | 525 | | 382 | | 900 | | 471 | |
| Alberta royalty tax credit (ARTC) | (153 | ) | (22 | ) | (417 | ) | (84 | ) |
| Total royalties | 3,470 | | 1,739 | | 7,039 | | 3,331 | |
| Per boe ($) | 11.89 | | 5.81 | | 11.71 | | 5.23 | |
2003-Q2 vs 2002-Q2
Total royalties increased by $1.7 million or 100%, to $3.5 million. Unit royalties expense increased by $6.08 or 105%, to $11.89 per boe due primarily to the following:
- An increase of $3.17 per boe due to royalty obligations associated with production from two new St. Albert oil wells where production is burdened by an 18% overriding and a 25% crown royalty, net of ARTC; and
- An increase of $2.91 per boe due to higher commodity prices.
On and effective July 7, 2003, we announced the repurchase of overriding royalty interests which burdened our total corporate production by 3% (see Note 4 to our Financial Statements for further details).
2003-Half vs 2002-Half
Total royalties increased by $3.7 million or 112%, to $7.0 million. Unit royalties expense increased by $6.48 or 124%, to $11.71 per boe due primarily to royalty obligations associated with production from two new St. Albert oil wells and higher commodity prices.
Production Costs
The following table shows our production and unit production costs per boe for the comparative periods presented.
($ 000’s unless otherwise stated)| | Three Months Ended June 30 | | Six Months Ended June 30 | |
| | 2003 | | 2002 | | 2003 | | 2002 | |
| Production costs(1) | 1,601 | | 1,605 | | 3,197 | | 3,758 | |
| Per boe ($) | 5.48 | | 5.37 | | 5.32 | | 5.90 | |
2003-Q2 vs 2002-Q2
Total production costs remained unchanged while unit production costs increased by a net of $0.11 or 2%, to $5.48 per boe mainly due to the following:
- A decrease of $0.58 per boe due to the elimination of monthly processing charges for St. Albert facilities acquired pursuant to a sales and leaseback agreement; and
- An increase of $0.68 per boe due to costs for our scheduled annual plant preventative maintenance and three-year boiler inspection programs at St. Albert not conducted in the same quarter last year.
2003-Half vs 2002-Half
Unit production costs decreased by a net of $0.58 or 10%, to $5.32 per boe mainly due to the elimination of monthly processing charges for St. Albert facilities acquired pursuant to a sales and leaseback agreement.
6
Amortization and Depletion Expense (A&D)
The following table shows our A&D expense and unit A&D expense per boe for the comparative periods presented.
($ 000’s unless otherwise stated)| | Three Months Ended June 30 | | Six Months Ended June 30 | |
| | 2003 | | 2002 | | 2003 | | 2002 | |
| A&D before the following: | | | | | | | | |
| Future removal and site restoration provision | 42 | | 101 | | 83 | | 202 | |
| Amortization of deferred items | 1,865 | | 1,267 | | 4,025 | | 3,835 | |
| Total A&D | 1,907 | | 1,368 | | 4,108 | | 4,037 | |
| Per boe ($) | 6.53 | | 4.57 | | 6.83 | | 6.34 | |
2003-Q2 vs 2002-Q2
Our total A&D increased by $0.5 million or 39%, to $1.9 million. Unit A&D costs increased by a net of $1.96 or 43%, to $6.53 per boe due to the following:
An increase of $0.32 per boe, the net result of new crude oil production volumes at a lower unit-of-production depletion rate at St. Albert;
An increase of $0.86 per boe due mainly to the recent annual revision in our proved producing natural gas reserves at St. Albert and Halkirk; and
An increase of $0.78 per boe due to a higher leasehold asset base.
2003-Half vs 2002-Half
Our total A&D increased by $0.1 million or 2%, to $4.1 million. Unit A&D costs increased by a net of $0.49 or 8%, to $6.83 per boe. Included in the net increase was $2.81 per boe caused by increased spending on various producing properties and our annual depletion rate updates. This was partially offset by a decrease of $2.32 per boe due to a Peavey/Morinville ceiling test adjustment taken in 2002-Half.
Exploration Expenses
The following table shows our exploration expenses and unit exploration expenses per boe for the comparative periods presented.
($ 000’s unless otherwise stated)| | Three Months Ended June 30 | | Six Months Ended June 30 | |
| | 2003 | | 2002 | | 2003 | | 2002 | |
| Drilling(1) | 555 | | 186 | | 654 | | 1,865 | |
| Seismic data activity | 131 | | 252 | | 869 | | 462 | |
| Other | 162 | | 13 | | 222 | | 57 | |
| Total exploration expenses | 848 | | 451 | | 1,745 | | 2,384 | |
| Per boe ($) | 2.90 | | 1.51 | | 2.90 | | 3.74 | |
| (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-Q2 vs 2002-Q2
Exploration costs increased by $0.4 million or 88%, to $0.8 million. Unit exploration expenses increased by a net of $1.39 or 92%, to $2.90 per boe due mainly to an unsuccessful drilling attempt at Wimborne, Alberta.
2003-Half vs 2002-Half
Exploration costs decreased by $0.6 million or 27%, to $1.7 million. Unit exploration expenses decreased by a net of $0.84 or 22%, to $2.90 per boe. The main reason for this decrease is that in 2003-Half costs incurred were related to the unsuccessful drilling attempt of one well, while in 2002-Half costs incurred were related to the unsuccessful drilling attempts of five wells.
Interest Expense
The following table shows our interest expense and unit interest expense per boe for the comparative periods presented.
($ 000’s unless otherwise stated)| | Three Months Ended June 30 | | Six Months Ended June 30 | |
| | 2003 | | 2002 | | 2003 | | 2002 | |
| Interest expense | 210 | | 151 | | 350 | | 281 | |
| Per boe ($) | 0.72 | | 0.50 | | 0.58 | | 0.44 | |
| 7 | | 2nd Quarter Interim Report as of June 30, 2003 |
2003-Q2 vs 2002-Q2
The variance between periods in our interest expense is due mainly to an increase in our operating loan balance that increased by $3.2 million to $14.3 million. Our effective interest rates were 5.4% and 4.4%, respectively.
2003-Half vs 2002-Half
Our effective interest rates were 5.1% and 4.2%, respectively.
General and Administrative Expenses (G&A)
The following table shows our G&A expenses and unit G&A expenses per boe for the comparative periods presented.
($ 000’s unless otherwise stated)| | Three Months Ended June 30 | | Six Months Ended June 30 | |
| | 2003 | | 2002 | | 2003 | | 2002 | |
| General and administrative | 880 | | 553 | | 1,609 | | 1,274 | |
| Per boe ($) | 3.02 | | 1.85 | | 2.68 | | 2.00 | |
2003-Q2 vs 2002-Q2
G&A increased by $0.3 million or 59% to $0.9 million. Unit G&A costs increased by a net $1.17 or 63%, to $3.02 per boe. Cost increases of $1.43 per boe were spent in various areas: new staff hires; employee performance bonuses; geophysical and mapping software usage; bank-loan renegotiation fees; computer networking charges; gas marketing advice; and legal professional fees. Cost decreases of $0.26 per boe were due to overhead credits earned through the operation of properties.
2003-Half vs 2002-Half
G&A increased by $0.3 million or 26%, to $1.6 million. Increased unit G&A costs reflect, in general, management’s plan for growth. New production forecasted by year-end is expected to impact unit G&A costs competitively.
Income Tax Expense
The following table shows our current and future income tax expenses for the comparative periods presented.
($ 000’s)| | Three Months Ended June 30 | | Six Months Ended June 30 | |
| | 2003 | | 2002 | | 2003 | | 2002 | |
| Income tax expense (recovery)(1) | | | | | | | | |
| Current | (672 | ) | 492 | | 1,012 | | 446 | |
| Future | 1,207 | | 14 | | 1,378 | | (840 | ) |
| Total | 535 | | 506 | | 2,390 | | (394 | ) |
| (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-Q2 vs 2002-Q2
Total income tax expense remained unchanged at $0.5 million. This expense was consistent with our pre-tax earnings.
2003-Half vs 2002-Half
Total income tax expense increased to $2.4 million from a recovery of $0.4 million. This expense was consistent with our pre-tax earnings. Our effective tax rate was 33.3% in 2003-Half and is in line with statutory tax rates.
LIQUIDITY AND CAPITAL RESOURCES
Our capital resources at the end of 2003-Q2 consisted of cash flow from operations, cash provided by the exercise of stock options and available lines of bank credit.
Our net debt decreased at the end of 2003-Q2 compared to the end of 2003-Q1 by $0.3 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, demand bank operating loan, supplemented by $1.3 million in cash provided by the exercise in 2003-Q2 of 780,000 stock options.
On May 16, 2003, our revolving, demand bank loan facility was increased from $21.0 million to $25.0 million. Principle balances outstanding bear interest at prime plus 3/8% (at June 30, 2003, the bank’s prime rate was 5%) and are collaterized by a general assignment of book debts and a floating charge debenture of $35.0 million covering all our assets. A standby fee of 1/8% per annum is levied on the unused portion of the facility.
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.
8
OUTLOOK FOR 2003
2003 Capital Expenditure and Exploration Expense Program
On and effective July 7, 2003, we announced the repurchase of overriding royalty interests which encumbered our total corporate production by 3%. This acquisition effectively increased our capital budget for Fiscal 2003 from $23.7 million to $30.2 million. Our exploration expense budget remained unchanged at $2.8 million.
Apart from the July 7, 2003 transaction mentioned above, 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 of which are reentries. 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
Our daily production exit rate for 2003-Q2 was 4,150 boe/d and we continue to target a year-end exit rate of 5,200 boe/d. Most of this anticipated growth is expected to come from increased natural gas, natural gas liquids and crude oil production at St. Albert, subject to on-going regulatory processes. The balance is expected to come from natural gas at Cypress/Chowade, subject to the completion of pipelining and availability of third-party processing.
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 | | 2nd Quarter Interim Report as of June 30, 2003 |
BALANCE SHEETS
(in Canadian Dollars)| | June 30 | | December 31 | |
| | 2003 | | 2002 | |
| | | (unaudited) | | | (audited) | |
| | | | | | | |
| Assets | | | | | | |
| Current | | | | | | |
| Accounts receivable | $ | 7,941,798 | | $ | 6,426,761 | |
| Prepaid expenses | | 532,466 | | | 351,771 | |
| Income taxes receivable | | – | | | 131,772 | |
| Total current assets | | 8,474,264 | | | 6,910,304 | |
| Natural gas and oil interests | | 43,318,072 | | | 36,568,076 | |
| Capital assets | | 245,565 | | | 168,366 | |
| | $ | 52,037,901 | | $ | 43,646,746 | |
| | | | | | | |
| Liabilities & Shareholders’ Equity | | | | | | |
| Current | | | | | | |
| Bank indebtedness | $ | 1,695,196 | | $ | 1,519,923 | |
| Operating loan | | 14,275,000 | | | 11,075,000 | |
| Accounts payable & accrued liabilities | | 7,861,255 | | | 11,133,844 | |
| Income taxes payable | | 545,226 | | | – | |
| Total current liabilities | | 24,376,677 | | | 23,728,767 | |
| Provision for future removal and site restoration | | 1,073,927 | | | 990,982 | |
| Future income tax liability | | 2,060,000 | | | 682,300 | |
| Total liabilities | | 27,510,604 | | | 25,402,049 | |
| Share capital | | 22,209,127 | | | 20,720,629 | |
| Retained earnings (deficit) | | 2,318,170 | | | (2,475,932 | ) |
| Total shareholders’ equity | | 24,527,297 | | | 18,244,697 | |
| | $ | 52,037,901 | | $ | 43,646,746 | |
Director | 
Director |
10
STATEMENTS OF OPERATIONS AND RETAINED EARNINGS (DEFICIT)
(in Canadian Dollars)| | Three Months Ended June 30 | | Six Months Ended June 30 | |
| | 2003 | | 2002 | | 2003 | | 2002 | |
| | (unaudited) | | | (unaudited) | | | (unaudited) | | | (unaudited) | |
| | | | | | | | | | | | | |
| Revenue | | | | | | | | | | | | |
| Natural gas, liquids and oil sales | $ | 10,923,640 | | $ | 7,194,396 | | $ | 25,232,049 | | $ | 13,802,119 | |
| Royalties | | (3,622,874 | ) | | (1,760,776 | ) | | (7,455,688 | ) | | (3,415,117 | ) |
| Production costs | | (1,600,764 | ) | | (1,605,426 | ) | | (3,197,332 | ) | | (3,757,533 | ) |
| | 5,700,002 | | | 3,828,194 | | | 14,579,029 | | | 6,629,469 | |
| Alberta royalty tax credit | | 152,972 | | | 22,262 | | | 416,965 | | | 83,754 | |
| | | 5,852,974 | | | 3,850,456 | | | 14,995,994 | | | 6,713,223 | |
| Expenses | | | | | | | | | | | | |
| General and administrative (schedule 1) | | 880,098 | | | 552,756 | | | 1,608,622 | | | 1,274,321 | |
| Interest expense on operating loan | | 210,737 | | | 151,820 | | | 350,082 | | | 281,245 | |
| Interest income | | (242 | ) | | (1,121 | ) | | (433 | ) | | (1,121 | ) |
| | 1,090,593 | | | 703,455 | | | 1,958,271 | | | 1,554,445 | |
| Earnings from operations | | | | | | | | | | | | |
| before the following: | | 4,762,381 | | | 3,147,001 | | | 13,037,723 | | | 5,158,778 | |
| Amortization and depletion (schedule 2) | | 1,907,239 | | | 1,368,345 | | | 4,108,242 | | | 4,037,195 | |
| Exploration expenses (schedule 3) | | 848,100 | | | 451,202 | | | 1,745,387 | | | 2,384,208 | |
| Gain on sale of natural gas | | | | | | | | | | | | |
| and oil interests | | – | | | (2,139 | ) | | – | | | (1,787 | ) |
| Earnings (loss) before taxes | | 2,007,042 | | | 1,329,593 | | | 7,184,094 | | | (1,260,838 | ) |
| Income tax expense (recovery) | | | | | | | | | | | | |
| – Current | | (671,482 | ) | | 491,778 | | | 1,012,292 | | | 445,865 | |
| – Future | | 1,206,800 | | | 14,000 | | | 1,377,700 | | | (840,000 | ) |
| Net earnings (loss) | | 1,471,724 | | | 823,815 | | | 4,794,102 | | | (866,703 | ) |
| Retained earnings (deficit), | | | | | | | | | | | | |
| beginning of period | | 846,446 | | | (4,321,539 | ) | | (2,475,932 | ) | | (2,547,470 | ) |
| Premium on purchase and | | | | | | | | | | | | |
| cancellation of common shares | | – | | | – | | | – | | | (83,551 | ) |
| Retained earnings (deficit), | | | | | | | | | | | | |
| end of period | $ | 2,318,170 | | $ | (3,497,724 | ) | $ | 2,318,170 | | $ | (3,497,724 | ) |
| Net earnings per share | | | | | | | | | | | | |
| basic | $ | 0.07 | | $ | 0.04 | | $ | 0.23 | | $ | (0.04 | ) |
| diluted | $ | 0.07 | | $ | 0.04 | | $ | 0.23 | | $ | (0.04 | ) |
| 11 | | 2nd Quarter Interim Report as of June 30, 2003 |
STATEMENTS OF CASH FLOWS
(in Canadian Dollars)| | Three Months Ended June 30 | | Six Months Ended June 30 | |
| | 2003 | | 2002 | | 2003 | | 2002 | |
| | | (unaudited) | | | (unaudited) | | | (unaudited) | | | (unaudited) | |
| | | | | | | | | | | | | |
| Operating activities | | | | | | | | | | | | |
| Net earnings (loss) | $ | 1,471,724 | | $ | 823,815 | | $ | 4,794,102 | | $ | (866,703 | ) |
| Add (deduct) items not involving cash: | | | | | | | | | | | | |
| Amortization and depletion | | 1,907,239 | | | 1,368,345 | | | 4,108,242 | | | 4,037,195 | |
| Future income taxes | | 1,206,800 | | | 14,000 | | | 1,377,700 | | | (840,000 | ) |
| Exploration expenses | | 848,100 | | | 451,202 | | | 1,745,387 | | | 2,384,208 | |
| Gain on sale of natural gas and oil interests | | – | | | (2,139 | ) | | – | | | (1,787 | ) |
| Cash flow from operations | | 5,433,863 | | | 2,655,223 | | | 12,025,431 | | | 4,712,913 | |
| Changes in non-cash working capital | | | | | | | | | | | | |
| affecting operating activities | | (322,066 | ) | | 1,145,933 | | | (1,363,856 | ) | | 2,847,083 | |
| Cash provided by operating activities | | 5,111,797 | | | 3,801,156 | | | 10,661,575 | | | 7,559,996 | |
| | | | | | | | | | | | | |
| Financing activities | | | | | | | | | | | | |
| Bank indebtedness | | 1,239,558 | | | (201,219 | ) | | 175,273 | | | 641,593 | |
| Operating loan | | 750,000 | | | 4,050,000 | | | 3,200,000 | | | 6,000,000 | |
| Shares issued for cash | | 1,291,243 | | | – | | | 1,488,498 | | | 325,120 | |
| Share repurchases | | – | | | – | | | – | | | (225,623 | ) |
| Cash provided by (used in) financing activities | | 3,280,801 | | | (4,251,219 | ) | | 4,863,771 | | | (5,258,910 | ) |
| | | | | | | | | | | | | |
| Investing activities | | | | | | | | | | | | |
| Purchase of capital assets | | (100,467 | ) | | (35,635 | ) | | (126,865 | ) | | (50,445 | ) |
| Natural gas and oil interests | | (5,489,833 | ) | | (514,898 | ) | | (10,725,627 | ) | | (1,876,509 | ) |
| Exploration expenses | | (848,100 | ) | | (451,202 | ) | | (1,745,387 | ) | | (2,384,208 | ) |
| Proceeds on sale of natural gas and oil interests | | – | | | 2,139 | | | – | | | 1,787 | |
| Changes in non-cash working capital | | | | | | | | | | | | |
| affecting investing activities | | (1,954,198 | ) | | 1,449,659 | | | (2,927,467 | ) | | 1,991,396 | |
| Cash (used in) provided by | | | | | | | | | | | | |
| investing activities | | (8,392,598 | ) | | 450,063 | | | (15,525,346 | ) | | (2,317,979 | ) |
| Increase (decrease) 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 | $ | 195,824 | | $ | 155,317 | | $ | 344,453 | | $ | 298,352 | |
| Income taxes | $ | 134,147 | | $ | 142,041 | | $ | 201,147 | | $ | 236,735 | |
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 and six-month periods ended June 30, 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.
Note 2. Common Share Capital
a) Issued and Outstanding Shares
The following table sets forth the issued and outstanding common shares for the comparative periods presented.
| | Six Months Ended June 30 | | Six Months Ended June 30 | |
| | 2003 | | 2002 | |
| | # | | $ | | # | | $ | |
| Outstanding, beginning of the period | 20,272,530 | | 20,720,629 | | 20,347,230 | | 20,731,474 | |
| Shares issued on exercise of stock options | | | | | | | | |
| during quarter ended: | | | | | | | | |
| – March 31 | 113,666 | | 197,255 | | 254,000 | | 325,120 | |
| – June 30 | 744,916 | | 1,291,243 | | – | | – | |
| Share repurchases/cancellations during | | | | | | | | |
| quarter ended March 31 | – | | – | | (139,000 | ) | (140,072 | ) |
| Outstanding, end of period | 21,311,112 | | 22,209,127 | | 20,462,230 | | 20,914,522 | |
b) Net Earnings per Share
The following table sets forth the computation of basic and diluted net earnings per share for the comparative periods presented.
(Units as stated)| | Three Months Ended June 30 | | Six Months Ended June 30 | |
| | 2003 | | 2002 | | 2003 | | 2002 | |
| Numerator: | | | | | | | | |
| Net earnings (loss) per period ($) | 1,471,724 | | 823,815 | | 4,794,102 | | (866,703 | ) |
| Denominator: | | | | | | | | |
| Weighted average number of common | | | | | | | | |
| shares outstanding (#) | 21,053,181 | | 20,567,771 | | 20,686,282 | | 20,653,029 | |
| Effect of dilutive stock options (#) | 552,329 | | 8,309 | | 507,715 | | 4,472 | |
| Basic net earnings (loss) per share ($) | 0.07 | | 0.04 | | 0.23 | | (0.04 | ) |
| Diluted net earnings (loss) per share ($) | 0.07 | | 0.04 | | 0.23 | | (0.04 | ) |
| 13 | | 2nd Quarter Interim Report as of June 30, 2003 |
c) Options Outstanding
The following table summarizes the status of the Company’s stock option plan for the comparative periods presented.
| | Six Months Ended June 30 | | Six Months Ended June 30 | |
| | 2003 | | 2002 | | 2003 | | 2002 | |
| | | Number of | | Weighted Average | |
| | | Shares | | Option Prices | |
| | # | | # | | $ | | $ | |
| Outstanding at December 31 | 2,077,750 | | 1,876,750 | | 1.83 | | 1.77 | |
| Granted during quarter ended: | | | | | | | | |
| – March 31 | 30,000 | | 307,500 | | 3.80 | | 1.75 | |
| – June 30 | 122,500 | | 57,500 | | 4.52 | | 1.65 | |
| Exercised during quarter ended: | | | | | | | | |
| – March 31 | (113,666 | ) | (254,000 | ) | 1.74 | | 1.28 | |
| – June 30 | (744,916 | ) | – | | 1.73 | | – | |
| Terminated during quarter ended: | | | | | | | | |
| – March 31 | (3,334 | ) | – | | 1.75 | | – | |
| – June 30 | (5,000 | ) | – | | 2.46 | | – | |
| Outstanding at June 30 | 1,363,334 | | 1,987,750 | | 2.19 | | 1.83 | |
| Options exercisable at June 30 | 1,064,667 | | 1,566,250 | | 2.24 | | 2.18 | |
Options outstanding as at June 30, 2003 had expiry dates ranging from July 14, 2003 to April 29, 2013.
Note 3. Stock-Based Compensation
Had the Company recognized compensation costs for the fair value of its stock option grants, the Company’s net earnings and net earnings per share would have been stated at the pro-forma amounts shown in the table below.
| | Three Months Ended June 30 | | Six Months Ended June 30 | |
| | 2003 | | 2002 | | 2003 | | 2002 | |
| Net earnings (loss): | | | | | | | | |
| As reported | 1,471,724 | | 823,815 | | 4,794,102 | | (866,703 | ) |
| Pro-forma | 1,210,140 | | 755,256 | | 4,502,084 | | (1,003,820 | ) |
| Basic net earnings per common share: | | | | | | | | |
| As reported | 0.07 | | 0.04 | | 0.23 | | (0.04 | ) |
| Pro-forma | 0.06 | | 0.04 | | 0.22 | | (0.05 | ) |
| Diluted net earnings per common share: | | | | | | | | |
| As reported | 0.07 | | 0.04 | | 0.23 | | (0.04 | ) |
| Pro-forma | 0.06 | | 0.04 | | 0.21 | | (0.05 | ) |
The fair values of the stock option grants during the quarter ended June 30, 2003 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 4%; dividend yield of 0%; estimated volatility of 57%; and estimated lives of 3 years. All assumptions used to determine fair values of stock option grants during the quarter ended June 30, 2002 were the same as those above except the risk-free average interest rate used was 5%.
Note 4. Subsequent Event
Prior to July 7, 2003, three of the Company’s officers received compensation pursuant to royalty agreements that were previously approved by shareholders. To each of the three officers, the Company paid an overriding royalty interest of 1% of the Company’s share of gross monthly production of all petroleum substances produced or deemed to be produced and marketed from or allocated to its producing wells. In the three and six-month periods ending June 30, 2003, the overriding royalty expense included in royalties was $471,135 and $794,876, respectively [three and six-month periods ending June 30, 2002 - $195,737; $391,241, respectively].
Effective July 7, 2003, the Company paid an aggregate of $6,516,000 to eliminate the obligations under the three overriding royalty agreements. The aggregate purchase price was paid by the issuance of 1,050,666 common shares of the Company and the payment of $1,000,000 in cash. The number of common shares was based on a price of $5.25 per share, such price having been determined according to a daily volume-weighted average price formula applied to recent trading as required by the rules of the Toronto Stock Exchange.
The aggregate purchase price is to be recorded as an interest in producing leaseholds and expensed as depletion in future Statements of Operations, based on the unit-of-production method.
14
SCHEDULE 1: GENERAL AND ADMINISTRATIVE
| | Three Months Ended June 30 | | Six Months Ended June 30 | |
| | 2003 | | 2002 | | 2003 | | 2002 | |
| | | (unaudited) | | | (unaudited) | | | (unaudited) | | | (unaudited) | |
| Advertising and promotion | $ | 49,680 | | $ | 50,715 | | $ | 96,084 | | $ | 139,427 | |
| Insurance | | 47,963 | | | 41,809 | | | 91,834 | | | 55,457 | |
| Interest | | 32,245 | | | 495 | | | 43,108 | | | 18,334 | |
| Office and printing | | 249,910 | | | 127,844 | | | 407,526 | | | 247,930 | |
| Professional fees | | 135,664 | | | 90,585 | | | 304,310 | | | 234,547 | |
| Provincial capital taxes | | 27 | | | 8,918 | | | 27 | | | 17,836 | |
| Regulatory and other fees | | 32,011 | | | 15,733 | | | 48,110 | | | 28,551 | |
| Rent | | 20,922 | | | 22,912 | | | 39,645 | | | 46,086 | |
| Salaries and benefits | | 437,453 | | | 259,538 | | | 751,030 | | | 651,610 | |
| Telephone | | 9,503 | | | 4,424 | | | 15,078 | | | 8,368 | |
| Travel | | 19,480 | | | 7,567 | | | 35,320 | | | 11,360 | |
| Cost recoveries | | (154,760 | ) | | (77,783 | ) | | (217,450 | ) | | (185,184 | ) |
| | $ | 880,098 | | $ | 552,756 | | $ | 1,608,622 | | $ | 1,274,322 | |
SCHEDULE 2: AMORTIZATION AND DEPLETION
| | Three Months Ended June 30 | | Six Months Ended June 30 | |
| | 2003 | | 2002 | | 2003 | | 2002 | |
| | | (unaudited) | | | (unaudited) | | | (unaudited) | | | (unaudited) | |
| Amortization and depletion | $ | 1,864,964 | | $ | 1,304,838 | | $ | 4,025,296 | | $ | 3,910,785 | |
| Future removal, site restoration | | 42,275 | | | 100,769 | | | 82,946 | | | 201,729 | |
| Amortization, deferred gain on sale | | – | | | (37,262 | ) | | – | | | (75,319 | ) |
| | $ | 1,907,239 | | $ | 1,368,345 | | $ | 4,108,242 | | $ | 4,037,195 | |
SCHEDULE 3: EXPLORATION EXPENSES
| | Three Months Ended June 30 | | Six Months Ended June 30 | |
| | 2003 | | 2002 | | 2003 | | 2002 | |
| | | (unaudited) | | | (unaudited) | | | (unaudited) | | | (unaudited) | |
| Drilling | $ | 555,000 | | $ | 186,274 | | $ | 654,327 | | $ | 1,864,853 | |
| Seismic data activity | | 130,674 | | | 252,179 | | | 868,530 | | | 462,324 | |
| Non-producing lease rentals | | 154,201 | | | (1,087 | ) | | 207,880 | | | 28,817 | |
| Property investigations | | 8,225 | | | 13,836 | | | 14,650 | | | 28,214 | |
| | $ | 848,100 | | $ | 451,202 | | $ | 1,745,387 | | $ | 2,384,208 | |
| 15 | | 2nd Quarter Interim Report as of June 30, 2003 |
