TABLE OF CONTENTS
TABLE OFCONTENTS | 1 | |||
GLOSSARY OF SELECTED TERMS | 2 | |||
MONETARY REFERENCES | 3 | |||
FORWARD LOOKING STATEMENTS | 3 | |||
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION | 3 | |||
ADDITIONAL INFORMATION RELATING TO BERKLEY’S RESERVE DATA | 4 | |||
Undeveloped Reserves | 4 | |||
Significant Factors and Uncertainties | 5 | |||
Future Development Costs | 5 | |||
OTHER OIL AND GAS INFORMATION | 17 | |||
Crude Oil and Natural Gas Wells | 17 | |||
Oil and Gas Properties | 17 | |||
Exploration and Development Drilling Activity | 17 | |||
Forward Contracts and Financial Instruments | 19 | |||
Abandonment and Reclamation Costs | 19 | |||
Acquisition, Exploration and Development Costs Incurred | 19 | |||
Production Volume by Area | 20 |
GLOSSARY OF SELECTED TERMS
The following are selected abbreviations and definitions of terms used herein:
“bbl” means billion barrels of total petroleum liquids;
“boe” means barrels of oil equivalent natural gas converted at 6 mscf of natural gas per barrel of oil;
“boe/day” means barrels of oil equivalent per day;
“bopd” means barrels of oil per day;
“Effective Date” means the effective date of the information contained in this Statement of Reserves Data and Other Oil and Gas Information, being December 31, 2004;
“mbbl” means thousands of barrels of oil;
“mboe” means thousands of barrels of oil equivalent;
“mbtu” means thousands of British Thermal Units;
“mcf” means thousands of cubic feet;
“mscf” means thousands of standard cubic feet;
“mscf/day” means thousands of standard cubic feet per day;
“mstb” means thousands of stock tank barrels;
“NGL’s” means natural gas liquids including condensate;
“NI 51-101” means National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities of the Canadian Securities Administrators;
“Preparation Date” means the date of preparation of this Statement of Reserves Data and Other Oil and Gas Information, being April 22, 2005;
“stb” means stock tank barrel; and
“Berkley” or the “Company” means Berkley Resources Inc., a British Columbia corporation.
References to oil, gas, natural gas liquids, reserves (gross, net, proved, probable, possible, developed, developed producing, developed non-producing, undeveloped), constant prices and costs, forecast prices and costs, operating costs, development costs, future net revenue and future income tax expenses, shall unless expressly stated to be to the contrary, have the meaning attributed to such terms as set out in NI 51-101, Companion Policy 51-101CP and all forms referenced therein.
MONETARY REFERENCES
All monetary references contained in this Statement of Reserves Data and Other Oil and Gas Information are in Canadian dollars unless otherwise specified.
FORWARD LOOKING STATEMENTS
This Statement of Reserves Data and Other Oil and Gas Information contains forward-looking statements. These statements relate to future events or Berkley’s future performance. All statements other than statements of historical fact are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may”, “will”, “should”, “expect”, “plan”, “anticipate”, “believe”, “estimate”, “predict”, “potential”, “continue”, or the negative of these terms or other comparable terminology. These statements are only predictions. Actual events or results may differ materially. Undue reliance should not be placed on these forward looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By its nature, forward-looking information involves numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur.
Although Berkley believes that the expectations reflected in the forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Berkley cannot guarantee future results, levels of activity, performance, or achievements. Moreover, Berkley does not assume responsibility for the accuracy and completeness of the forward-looking statements.
Statements relating to “reserves” or “resources” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the resources and reserves described can be profitably produced in the future. All forward-looking statements contained in this Statement of Reserves Data and Other Oil and Gas Information are expressly qualified by this cautionary statement. Berkley is not under any duty to update any of the forward-looking statements after the date hereof to conform such statements to actual results or to changes in Berkley’s expectations.
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION
In accordance with the requirements of NI 51-101, the following Statement of Reserves Data and Other Oil and Gas Information for Berkley is dated with an Effective Date of December 31, 2004 and a Preparation Date of April 22, 2005.
Gilbert Laustsen Jung Associates Ltd. and DeGolyer and MacNaughton Canada Limited (“Evaluators”) prepared reserve reports, dated as of April 22, 2005 and April 15, 2005 respectively, with an effective date of December 31, 2004 (the “ Reports”) which evaluate the proved and probable crude oil, natural gas and NGL reserves attributable to Berkley’s interests in its properties and net present value of estimated future cash flow from such reserves, based on both forecasted and constant price and cost assumptions. These Reports account for approximately 86% of the Company’s reserves. For the remaining 14% of reserves, being for one property, the Company extracted the required information from a reserve report prepared by Chapman Petroleum Engineering Ltd. which was prepared for another company, being the operator and largest working interest owner. The reserves information contained in all Reports was prepared and is presented in accordance with the requirements of NI 51-101.
In preparing its Reports, the Evaluators obtained basic information from Berkley, which included land data, well information, geological information, reservoir studies, estimates of on-stream dates, contract information, current hydrocarbon product prices, operating costs data, capital budget forecasts, financial data and future operating plans. Other engineering, geological or economic data required to conduct the evaluations and upon which these Reports are based, was obtained from public records, other operators and from the Evaluator’s non-confidential files. The extent and character of ownership and the accuracy of all factual data supplied for the independent evaluations, from all sources, was accepted by the Evaluators as represented by Berkley.
The following tables, based on the reports, show the estimated share of Berkley’s crude oil, natural gas and NGL reserves in its properties and the net present value of estimated future net revenue for these reserves, using constant and forecast prices and costs as indicated.All evaluations of the present value of estimated future net revenue in these reports are stated after provision for estimated future capital expenditures, well abandonment and reclamation costs (including the offsetting salvage value of tangible equipment after abandonment) but prior to income taxes and indirect costs and do not necessarily represent the fair market value of the reserves. The recovery and reserve estimates of Berkley’s oil, NGL and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein.
References to oil, gas, natural gas liquids, reserves (gross, net, proved, probable, possible, developed, developed producing, developed non-producing, undeveloped), constant prices and costs, forecast prices and costs, operating, costs, development costs, future net revenue and future income tax expenses shall, unless expressly stated to be to the contrary, have the meaning attributed to such terms as set out in National Instrument 51-101, Companion Policy 51-101CP and all forms referenced therein.
BERKLEY RESOURCES INC.
SUMMARY OF OIL AND GAS RESERVES AND NET PRESENT VALUE OF FUTURE NET REVENUE ITEM 2.1
Constant Prices and Costs
Proved Reserves and Net Present Value
As at December 31, 2004
Total Company
Constant Case
Before Tax | After Tax | |||||||||||||||||||||||||||||||||||||||||||||
Oil | NGL’s | Natural Gas | Discounted At | Discounted At | ||||||||||||||||||||||||||||||||||||||||||
Gross(1) | Net(2) Gross(1) | Net(2) | Gross(1) | Net(2) | 0% | 10% | 0% 10% | |||||||||||||||||||||||||||||||||||||||
(MBbl) | (MBbl) | (MBbl) | (MBbl) | (MMcf) | (MMcf) | (M$) | (M$) | (M$) | (M$) | |||||||||||||||||||||||||||||||||||||
Proved Developed Producing | 5 | 4 | 3 | 2 | 222 | 179 | 1,228 | 887 | 1,228 | 887 | ||||||||||||||||||||||||||||||||||||
Developed Non-Producing | 28 | 24 | 41 | 22 | 1,008 | 583 | 5,706 | 4,391 | 5,706 | 4,391 | ||||||||||||||||||||||||||||||||||||
Undeveloped | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
Total Proved | 33 | 28 | 44 | 24 | 1,230 | 762 | 6,934 | 5,278 | 6,934 | 5,278 | ||||||||||||||||||||||||||||||||||||
Notes:
(1) | Gross Reserves means Berkley’s working interest (operating and non-operating) share before deduction of royalties and income taxes. |
(2) | Net Reserves means Berkley’s working interest (operating and non-operating) share after deduction of royalties but before deduction of income taxes. |
(3) | After tax evaluations were not prepared as the Company will be non-taxable for the foreseeable future. |
Additional Information — Future Net Revenue
As at December 31, 2004
Total Company
Constant Case
Future Gross | Future Net Revenue | Future Net Revenue | ||||||||||||||||||||||||||||||
Revenue | Royalties Net of | Operating Costs | Development Costs | Abandonment Costs | Before Income Tax | Future Income Tax | After Income Tax | |||||||||||||||||||||||||
(M$) | ARTC (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | |||||||||||||||||||||||||
Total Proved | 13,197 | (3,301 | ) | (2,403 | ) | (504 | ) | (55 | ) | 6,934 | — | 6,934 | ||||||||||||||||||||
Additional Information — Future Net Revenue By Production Group
(Before Future Income Tax)
As at December 31, 2004
Total Company
Constant Case
Discounted at 10% | ||||||
Reserves Category | Production Group | (M$) | ||||
Total Proved | Oil (MBbl) | 971 | ||||
Total Proved | NGL’s (MBbl) | 840 | ||||
Total Proved | Natural Gas (MMcf) | 3,467 | ||||
1
Proved Reserves and Net Present Value
As at December 31, 2004
John Lake Area, Alberta
Constant Case
Before Tax | After Tax | |||||||||||||||||||||||||||||||||||||||
Oil | NGL’s | Natural Gas | Discounted At | Discounted At | ||||||||||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | 0% | 10% | 0% | 10% | |||||||||||||||||||||||||||||||
(MBbl) | (MBbl) | (MBbl) | (MBbl) | (MMcf) | (MMcf) | (M$) | (M$) | (M$) | (M$) | |||||||||||||||||||||||||||||||
Proved | ||||||||||||||||||||||||||||||||||||||||
Developed Producing | — | — | — | — | 105 | 76 | 390 | 306 | 390 | 306 | ||||||||||||||||||||||||||||||
Developed Non-Producing | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
Undeveloped | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
Total Proved | — | — | — | — | 105 | 76 | 390 | 306 | 390 | 306 | ||||||||||||||||||||||||||||||
Evaluated By Degolyer and MacNaughton Canada Limited
Additional Information — Future Net Revenue
As at December 31, 2004
John Lake Area, Alberta
Constant Case
Future Gross | Future Net Revenue | Future Net Revenue | ||||||||||||||||||||||||||||||
Revenue | Royalties Net of | Operating Costs | Development Costs | Abandonment Costs | Before Income Tax | Future Income Tax | After Income Tax | |||||||||||||||||||||||||
(M$) | ARTC (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | |||||||||||||||||||||||||
Total Proved | 659 | (131 | ) | (121 | ) | — | (17 | ) | 390 | — | 390 | |||||||||||||||||||||
Additional Information — Future Net Revenue By Production Group
(Before Future Income Tax)
As at December 31, 2004
John Lake Area, Alberta
Constant Case
Discounted at 10% | ||||||
Reserves Category | Production Group | (M$) | ||||
Total Proved | Natural Gas (MMcf) | 306 | ||||
Proved Reserves and Net Present Value
As at December 31, 2004
Brazeau, Carbon, Leduc Areas, Alberta
Constant Case
Before Tax | After Tax | |||||||||||||||||||||||||||||||||||||||
Oil | NGL’s | Natural Gas | Discounted At | Discounted At | ||||||||||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | 0% | 10% | 0% | 10% | |||||||||||||||||||||||||||||||
(MBbl) | (MBbl) | (MBbl) | (MBbl) | (MMcf) | (MMcf) | (M$) | (M$) | (M$) | (M$) | |||||||||||||||||||||||||||||||
Proved Developed Producing | — | — | 3 | 2 | 117 | 103 | 581 | 371 | 581 | 371 | ||||||||||||||||||||||||||||||
Developed Non-Producing | — | — | 41 | 22 | 1,008 | 583 | 4,817 | 3,630 | 4,817 | 3,630 | ||||||||||||||||||||||||||||||
Undeveloped | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
Total Proved | — | — | 44 | 24 | 1,125 | 686 | 5,398 | 4,001 | 5,398 | 4,001 | ||||||||||||||||||||||||||||||
Evaluated by Gilbert Laustsen Jung Associates Ltd.
Additional Information — Future Net Revenue
As at December 31, 2004
Brazeau, Carbon, Leduc Areas, Alberta
Constant Case
Future Gross | �� | Future Net Revenue | Future Net Revenue | |||||||||||||||||||||||||||||
Revenue | Royalties Net of | Operating Costs | Development Costs | Abandonment Costs | Before Income Tax | Future Income Tax | After Income Tax | |||||||||||||||||||||||||
(M$) | ARTC (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | |||||||||||||||||||||||||
Total Proved | 10,572 | (2,869 | ) | (1,839 | ) | (450 | ) | (16 | ) | 5,398 | — | 5,398 | ||||||||||||||||||||
Additional Information — Future Net Revenue by Production Group
(Before Future Income Tax)
As at December 31, 2004
Brazeau, Carbon, Leduc Areas, Alberta
Constant Case
Discounted at 10% | ||||||
Reserves Category | Production Group | (M$) | ||||
Total Proved | NGL’s (MBbl) | 840 | ||||
Total Proved | Natural Gas (MMcf) | 3,161 | ||||
Proved Reserves and Net Present Value
As at December 31, 2004
Senex Area, Alberta
Constant Case
Before Tax | After Tax | |||||||||||||||||||||||||||||||||||||||
Oil | NGL’s | Natural Gas | Discounted At | Discounted At | ||||||||||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | 0% | 10% | 0% | 10% | |||||||||||||||||||||||||||||||
(MBbl) | (MBbl) | (MBbl) | (MBbl) | (MMcf) | (MMcf) | (M$) | (M$) | (M$) | (M$) | |||||||||||||||||||||||||||||||
Proved Developed Producing | 5 | 4 | — | — | — | — | 257 | 210 | 257 | 210 | ||||||||||||||||||||||||||||||
Developed Non-Producing | 28 | 24 | — | — | — | — | 889 | 761 | 889 | 761 | ||||||||||||||||||||||||||||||
Undeveloped | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
Total Proved | 33 | 28 | — | — | — | — | 1,146 | 971 | 1,146 | 971 | ||||||||||||||||||||||||||||||
Additional Information — Future Net Revenue
As at December 31, 2004
Senex Area, Alberta
Constant Case
Future Gross | Future Net Revenue | Future Net Revenue | ||||||||||||||||||||||||||||||
Revenue | Operating Costs | Development Costs | Abandonment Costs | Before Income Tax | Future Income Tax | After Income Tax | ||||||||||||||||||||||||||
(M$) | Royalties (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | |||||||||||||||||||||||||
Total Proved | 1,966 | (301 | ) | (443 | ) | (54 | ) | (22 | ) | 1,146 | — | 1,146 | ||||||||||||||||||||
Additional Information — Future Net Revenue by Production Group
(Before Future Income Tax)
As at December 31, 2004
Senex Area, Alberta
Constant Case
Discounted at 10% | ||||||
Reserves Category | Production Group | (M$) | ||||
Total Proved | Oil (MBbl) | 971 | ||||
2
BERKLEY RESOURCES INC.
SUMMARY OF OIL AND GAS RESERVES AND NET PRESENT VALUE OF FUTURE NET
REVENUE ITEM 2.2
Forecast Prices and Costs
Proved Plus Probable Reserves and Net Present Value
As at December 31, 2004
Total Company
Forecast Case
Oil | NGL’s | Natural Gas | Before Tax Discounted At | After Tax Discounted At | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gross(1) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
up> | Net(2) | Gross(1) Net(2) | Gross(1) | Net(2) | 0% | 5% | 10% 15% | 20% | 0% | 5% | 10% | 15% | 20% | |||||||||||||||||||||||||||||||||||||||||||||||||||
(MBbl | (MBbl) | (MBbl) | (MBbl) | (MMcf) | (MMcf) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | |||||||||||||||||||||||||||||||||||||||||||||||||
Proved | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Developed Producing | 5 | 4 | 3 | 2 | 223 | 181 | 1,009 | 859 | 751 | 673 | 611 | 1,009 | 859 | 751 | 673 | 611 | ||||||||||||||||||||||||||||||||||||||||||||||||
Developed Non-Producing | 28 | 24 | 41 | 23 | 1,022 | 591 | 4,815 | 4,193 | 3,719 | 3,348 | 3,049 | 4,815 | 4,193 | 3,719 | 3,348 | 3,049 | ||||||||||||||||||||||||||||||||||||||||||||||||
Undeveloped | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Total Proved | 33 | 28 | 44 | 25 | 1,245 | 772 | 5,824 | 5,052 | 4,470 | 4,021 | 3,660 | 5,824 | 5,052 | 4,470 | 4,021 | 3,660 | ||||||||||||||||||||||||||||||||||||||||||||||||
Probable | 73 | 56 | 5 | 3 | 169 | 111 | 2,335 | 1,707 | 1,328 | 1,077 | 903 | 2,335 | 1,707 | 1,328 | 1,077 | 903 | ||||||||||||||||||||||||||||||||||||||||||||||||
Total Proved plus Probable | 106 | 84 | 49 | 28 | 1,414 | 883 | 8,159 | 6,759 | 5,798 | 5,098 | 4,563 | 8,159 | 6,759 | 5,798 | 5,098 | 4,563 | ||||||||||||||||||||||||||||||||||||||||||||||||
Notes:
(1) | Gross Reserves means Berkley’s working interest (operating and non-operating) share before deduction of royalties and income taxes. |
(2) | Net Reserves means Berkley’s working interest (operating and non-operating) share after deduction of royalties but before deduction of income taxes. |
(3) After tax evaluations were not prepared as the Company will be non-taxable for the foreseeable future
Additional Information – Future Net Revenue
As at December 31, 2004
Total Company
Forecast Case
Future Gross | Future Net Revenue | Future Net Revenue | ||||||||||||||||||||||||||||||
Revenue | Royalties Net of | Operating Costs | Development Costs | Abandonment Costs | Before Income Tax | Future Income Tax | After Income Tax | |||||||||||||||||||||||||
(M$) | ARTC (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | |||||||||||||||||||||||||
Total Proved | 11,984 | (2,961 | ) | (2,629 | ) | (504 | ) | (66 | ) | 5,824 | — | 5,824 | ||||||||||||||||||||
Total Proved plus Probable | 16,840 | (3,800 | ) | (4,103 | ) | (640 | ) | (138 | ) | 8,159 | — | 8,159 | ||||||||||||||||||||
Additional Information — Future Net Revenue by Production Group
(Before Future Income Tax)
As at December 31, 2004
Total Company
Forecast Case
Discounted at 10% | ||||||
Reserves Category | Production Group | (M$) | ||||
Total Proved | Oil (MBbl) | 579 | ||||
Total Proved | NGL’s (MBbl) | 2,826 | ||||
Total Proved | Natural Gas (MMcf) | 1,065 | ||||
Total Proved plus Probable | Oil (MBbl) | 1,546 | ||||
Total Proved plus Probable | NGL’s (MBbl) | 3,055 | ||||
Total Proved plus Probable | Natural Gas (MMcf) | 1,197 | ||||
Proved Plus Probable Reserves and Net Present Value
As at December 31, 2004
John Lake Area, Alberta
Forecast Case
Oil | NGL’s | Natural Gas | Before Tax Discounted At | After Tax Discounted At | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | 0% | 5% | 10% | 15% | 20% | 0% | 5% | 10% | 15% | 20% | |||||||||||||||||||||||||||||||||||||||||||||||||
(MBbl | (MBbl) | (MBbl) | (MBbl) | (MMcf) | (MMcf) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | |||||||||||||||||||||||||||||||||||||||||||||||||
Proved | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Developed Producing | — | — | — | — | 106 | 78 | 390 | 349 | 314 | 286 | 262 | 390 | 349 | 314 | 286 | 262 | ||||||||||||||||||||||||||||||||||||||||||||||||
Developed Non-Producing | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||
Undeveloped | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Total Proved | 106 | 78 | 390 | 349 | 314 | 286 | 262 | 390 | 349 | 314 | 286 | 262 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Probable | — | — | — | — | 36 | 27 | 120 | 90 | 71 | 56 | 45 | 120 | 90 | 71 | 56 | 45 | ||||||||||||||||||||||||||||||||||||||||||||||||
Total Proved plus Probable | — | — | — | — | 142 | 105 | 510 | 439 | 385 | 342 | 307 | 510 | 439 | 385 | 342 | 307 | ||||||||||||||||||||||||||||||||||||||||||||||||
Evaluated by Degolyer and MacNaughton Canada Limited
Additional Information — Future Net Revenue
As at December 31, 2004
John Lake Area, Alberta
Forecast Case
Future Gross | Future Net Revenue | Future Net Revenue | ||||||||||||||||||||||||||||||
Revenue | Royalties Net of | Operating Costs | Development Costs | Abandonment Costs | Before Income Tax | Future Income Tax | After Income Tax | |||||||||||||||||||||||||
(M$) | ARTC (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | |||||||||||||||||||||||||
Total Proved | 671 | (128 | ) | (133 | ) | — | (20 | ) | 390 | — | 390 | |||||||||||||||||||||
Total Proved plus Probable | 881 | (167 | ) | (183 | ) | — | (21 | ) | 510 | — | 510 | |||||||||||||||||||||
Additional Information — Future Net Revenue By Production Group
(Before Future Income Tax)
As at December 31, 2004
John Lake Area, Alberta
Forecast Case
Discounted at 10% | ||||||
Reserves Category | Production Group | (M$) | ||||
Total Proved | Natural Gas (MMcf) | 314 | ||||
Total Proved plus Probable | Natural Gas (MMcf) | 385 | ||||
Proved Plus Probable Reserves and Net Present Value
As at December 31, 2004
Brazeau, Carbon, Leduc Areas, Alberta
Forecast Case
Oil | NGL’s | Natural Gas | Before Tax Discounted At | After Tax Discounted At | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | 0% | 5% | 10% | 15% | 20% | 0% | 5% | 10% | 15% | 20% | |||||||||||||||||||||||||||||||||||||||||||||||||
(MBbl | (MBbl) | (MBbl) | (MBbl) | (MMcf) | (MMcf) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | |||||||||||||||||||||||||||||||||||||||||||||||||
Proved | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Developed Producing | — | — | 3 | 2 | 117 | 103 | 489 | 388 | 322 | 278 | 245 | 489 | 388 | 322 | 278 | 245 | ||||||||||||||||||||||||||||||||||||||||||||||||
Developed Non-Producing | — | — | 41 | 23 | 1,022 | 591 | 4,234 | 3,677 | 3,255 | 2,926 | 2,662 | 4,234 | 3,677 | 3,255 | 2,926 | 2,662 | ||||||||||||||||||||||||||||||||||||||||||||||||
Undeveloped | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Total Proved | — | — | 44 | 25 | 1,139 | 694 | 4,723 | 4,065 | 3,577 | 3,204 | 2,907 | 4,723 | 4,065 | 3,577 | 3,204 | 2,907 | ||||||||||||||||||||||||||||||||||||||||||||||||
Probable | — | — | 5 | 3 | 133 | 84 | 559 | 390 | 290 | 226 | 184 | 559 | 390 | 290 | 226 | 184 | ||||||||||||||||||||||||||||||||||||||||||||||||
Total Proved plus Probable | — | — | 49 | 28 | 1,272 | 778 | 5,282 | 4,455 | 3,867 | 3,430 | 3,091 | 5,282 | 4,455 | 3,867 | 3,430 | 3,091 | ||||||||||||||||||||||||||||||||||||||||||||||||
Evaluated by Gilbert Laustsen Jung Associates Ltd.
Additional Information – Future Net Revenue
As at December 31, 2004
Brazeau, Carbon, Leduc Areas, Alberta
Forecast Case
Future Gross | Future Net Revenue | Future Net Revenue | ||||||||||||||||||||||||||||||
Revenue | Royalties Net of | Operating Costs | Development Costs | Abandonment Costs | Before Income Tax | Future Income Tax | After Income Tax | |||||||||||||||||||||||||
(M$) | ARTC (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | |||||||||||||||||||||||||
Total Proved | 9,811 | (2,613 | ) | (2,004 | ) | (450 | ) | (21 | ) | 4,723 | — | 4,723 | ||||||||||||||||||||
Total Proved plus Probable | 10,940 | (2,899 | ) | (2,287 | ) | (450 | ) | (22 | ) | 5,282 | — | 5,282 | ||||||||||||||||||||
Additional Information — Future Net Revenue By Production Group
(Before Future Income Tax)
As at December 31, 2004
Brazeau, Carbon, Leduc Areas, Alberta
Forecast Case
Discounted at 10% | ||||||
Reserves Category | Production Group | (M$) | ||||
Total Proved | NGL’s (MBbl) | 2,826 | ||||
Total Proved | Natural Gas (MMcf) | 751 | ||||
Total Proved plus Probable | NGL’s (MBbl) | 3,055 | ||||
Total Proved plus Probable | Natural Gas (MMcf) | 812 | ||||
Proved Plus Probable Reserves and Net Present Value
As at December 31, 2004
Senex Area, Alberta
Forecast Case
Oil | NGL’s | Natural Gas | Before Tax Discounted At | After Tax Discounted At | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | 0% | 5% | 10% | 15% | 20% | 0% | 5% | 10% | 15% | 20% | |||||||||||||||||||||||||||||||||||||||||||||||||
(MBbl | (MBbl) | (MBbl) | (MBbl) | (MMcf) | (MMcf) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | |||||||||||||||||||||||||||||||||||||||||||||||||
Proved | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Developed Producing | 5 | 4 | — | — | — | — | 130 | 122 | 115 | 109 | 104 | 130 | 122 | 115 | 109 | 104 | ||||||||||||||||||||||||||||||||||||||||||||||||
Developed Non-Producing | 28 | 24 | — | — | — | — | 581 | 516 | 464 | 422 | 387 | 581 | 516 | 464 | 422 | 387 | ||||||||||||||||||||||||||||||||||||||||||||||||
Undeveloped | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Total Proved | 33 | 28 | — | — | — | — | 711 | 638 | 579 | 531 | 491 | 711 | 638 | 579 | 531 | 491 | ||||||||||||||||||||||||||||||||||||||||||||||||
Probable | 73 | 56 | — | — | — | — | 1,656 | 1,227 | 967 | 795 | 674 | 1,656 | 1,227 | 967 | 795 | 674 | ||||||||||||||||||||||||||||||||||||||||||||||||
Total Proved plus Probable | 106 | 84 | — | — | — | — | 2,367 | 1,865 | 1,546 | 1,326 | 1,165 | 2,367 | 1,865 | 1,546 | 1,326 | 1,165 | ||||||||||||||||||||||||||||||||||||||||||||||||
3
Additional Information — Future Net Revenue
As at December 31, 2004
Senex Area, Alberta
Forecast Case
Future Gross | Future Net Revenue | Future Net Revenue | ||||||||||||||||||||||||||||||
Revenue | Operating Costs | Development Costs | Abandonment Costs | Before Income Tax | Future Income Tax | After Income Tax | ||||||||||||||||||||||||||
(M$) | Royalties (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | |||||||||||||||||||||||||
Total Proved | 1,502 | (220 | ) | (492 | ) | (54 | ) | (25 | ) | 711 | — | 711 | ||||||||||||||||||||
Total Proved plus Probable | 5,019 | (734 | ) | (1,633 | ) | (190 | ) | (95 | ) | 2,367 | — | 2,367 | ||||||||||||||||||||
Additional Information — Future Net Revenue By Production Group
(Before Future Income Tax)
As at December 31, 2004
Senex Area, Alberta
Forecast Case
Discounted at 10% | ||||||
Reserves Category | Production Group | (M$) | ||||
Total Proved | Oil (MBbl) | 579 | ||||
Total Proved plus Probable | Oil (MBbl) | 1,546 | ||||
PRICING ASSUMPTIONS
Constant Prices and Costs — December 31, 2004
Gilbert Laustsen Jung Associates Ltd. used the following price and exchange rate and inflation rate assumptions as of December 31, 2004 in estimating Berkley’s reserves data using constant prices and costs.
Crude Oil and Natural Gas Liquids Prices, C$/Bbl.
Inflation | Exchange | |||||||||||||||||
Oil | Natural Gas | NGL’s | Rate | Rate | ||||||||||||||
West Texas Intermediate ($US) | Edmonton Light Sweet Crude (Cdn$/stb) | Alberta Par Price ($/mmbtu) | Alberta Spot Sales ($/mmbtu) | ($/bbl)) | % Per Annum | $US/$Cdn | ||||||||||||
43.45 | 46.54 | - | 6.79 | - | 0 | — | ||||||||||||
Forecast Prices and Costs
December 31, 2004
Gilbert Laustsen Jung Associates Ltd. used the following price and exchange rate and inflation rate assumptions as of December 31, 2004 in estimating Berkley’s reserves data using forecast prices and costs.
Crude Oil and Natural Gas Liquids Prices, C$/Bbl.
Inflation | Exchange | |||||||||||||||||||||||||||
Oil | Natural Gas | NGL’s | Rate | Rate | ||||||||||||||||||||||||
Year | West Texas Intermediate ($US) | Edmonton Light Sweet Crude (Cdn$/stb) | Alberta Par Price ($/mmbtu) | Alberta Spot Sales ($/mmbtu) | ($/bbl)) | % Per Annum | $US/$Cdn | |||||||||||||||||||||
2005 | 42.00 | 50.25 | 6.30 | 6.35 | 50.75 | 2.0 | 0.82 | |||||||||||||||||||||
2006 | 40.00 | 47.75 | 6.10 | 6.10 | 48.25 | 2.0 | 0.82 | |||||||||||||||||||||
2007 | 38.00 | 45.50 | 5.90 | 5.90 | 46.00 | 2.0 | 0.82 | |||||||||||||||||||||
2008 | 36.00 | 43.25 | 5.75 | 5.75 | 43.75 | 2.0 | 0.82 | |||||||||||||||||||||
2009 | 34.00 | 40.75 | 5.75 | 5.75 | 41.25 | 2.0 | 0.82 | |||||||||||||||||||||
RECONCILATIONS OF CHANGES IN RESERVES AND FUTURE NET REVENUE
Reserves Reconciliation
The following table sets forth a reconciliation of Berkley’s total net proved, probable and proved plus probable reserves as at December 31, 2004 against such reserves as at December 31, 2003 based on forecast price and cost assumptions:
LIGHT AND MEDIUM OIL | ASSOCIATED AND NON-ASSOCIATED GAS | NATURAL GAS LIQUIDS | ||||||||||||||||||||||||||||||||||
Net Proved Plus | Net Proved Plus | Net Proved Plus | ||||||||||||||||||||||||||||||||||
Factors | Net Proved (mbbl) | Net Probable (mbbl) | Probable (mbbl) | Net Proved (mmcf) | Net Probable (mmcf) | Probable (mmcf) | Net Proved (mbbl) | Net Probable (mbbl) | Probable (mbbl) | |||||||||||||||||||||||||||
December 31, 2003 | 196 | 4 | 200 | 192 | 30 | 222 | — | — | — | |||||||||||||||||||||||||||
Extensions | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
Improved Recovery | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
Technical Revisions | — | — | — | 80 | — | 80 | — | — | — | |||||||||||||||||||||||||||
Discoveries | — | 56 | 56 | 579 | 81 | 660 | 25 | 3 | 28 | |||||||||||||||||||||||||||
Acquisitions | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
Dispositions | (157 | ) | (4 | ) | (161 | ) | (15 | ) | — | (15 | ) | — | — | — | ||||||||||||||||||||||
Economic Factors | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
Production | (11 | ) | — | (11 | ) | (64 | ) | — | (64 | ) | — | — | — | |||||||||||||||||||||||
December 31, 2004 | 28 | 56 | 84 | 772 | 111 | 883 | 25 | 3 | 28 | |||||||||||||||||||||||||||
Future Net Revenue Reconciliation
The following table sets forth a reconciliation of the estimate of the future net revenue discounted at 10%, attributable to net proved reserves as evaluated in Reports using constant prices and cost assumptions:
Before Tax | After Tax | |||||||
Period and Factor | 2004 (M$) | 2004 (M$) | ||||||
December 31, 2003 | 1,061 | 1,061 | ||||||
Sales and Transfers of Oil and Gas Produced during the Period Net of Production Costs and Royalties(1) | (451 | ) | (451 | ) | ||||
Net Change in Sales and Transfer Prices and in Production Costs and Royalties related to Future Production(2) | 1,000 | 1,000 | ||||||
Changes in Previously Estimated Future Development Costs Incurred During the Period(3) | — | — | ||||||
Changes in Estimated Future Development Costs (4) | 75 | 75 | ||||||
Net Change Resulting from Extensions and Improved Recovery(5) | — | — | ||||||
Net Change Resulting from Discoveries(5) | 3,254 | 3,254 | ||||||
Changes Resulting from Acquisitions of Reserves(5) | — | — | ||||||
Changes Resulting from Dispositions of Reserves(5) | (204 | ) | (204 | ) | ||||
Net Change Resulting from Revisions in Quantity Estimates | 543 | 543 | ||||||
Accretion of Discount(6) | — | — | ||||||
Net Change of Income Taxes(7) | — | — | ||||||
Other Significant Factors(8) | — | — | ||||||
December 31, 2004 | 5,278 | 5,278 | ||||||
Notes:
(1) Company actual before income taxes, excluding G&A.
(2) The impact of changes in prices and other economic factors on future net revenue
(3) | Actual capital expenditures relating to the exploration, development and production of oil and gas reserves. |
(4) The change in forecast development costs.
(5) End of period net present value of the related reserves.
(6) Estimated as 10% of the beginning of period net present value.
(7) | The difference between forecast income taxes at beginning of period and the actual taxes for the period plus forecast income taxes at the end of period. |
(8) | Includes changes due to revised production profiles, development timing, operating costs, royalty rates, actual price received in 2003 versus forecast, etc. |
ADDITIONAL INFORMATION RELATING TO BERKLEY’S RESERVE DATA
Significant Factors and Uncertainties
The process of estimating oil and gas reserves is complex. It requires significant judgments and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas processing and costs change. The reserve estimates contained herein are based on current production forecasts, prices and economic conditions and are evaluated by independent engineering firms.
As circumstances change and additional data become available, reserve estimates also change. Estimates made are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, prices, economic conditions and governmental restrictions.
Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential science. As a result, the subjective decisions, new geological or production information and a changing environment may impact these estimates. Revisions to reserve estimates can arise from changes in year-end oil and gas prices and reservoir performance. Such revisions can be either positive or negative. The reserve estimates of the Company’s oil, NGL and natural gas reserves provided in this Statement of Reserves Data and Other Oil and Gas Information are estimates only and there is no assurance or guarantee that the estimated reserves will be recovered. Actual reserves may be greater or less than the estimates provided herein.
OTHER OIL AND GAS INFORMATION
Crude Oil and Natural Gas Wells
The following table summarizes the Company’s interest, as at December 31, 2004, in producing and non-producing crude oil and natural gas wells:
Oil | Gas | |||||||||||||||||||||||||||||||
Location | Producing | Non-Producing | Producing | Non-Producing | ||||||||||||||||||||||||||||
| | | ||||||||||||||||||||||||||||||
Gross(1) | Net(2) | Gross(1) | Net(2) | Gross(1) | Net(\2) | Gross(1) | Net(2) | |||||||||||||||||||||||||
Alberta | 6.0 | 0.9 | — | — | 19.0 | 1.2 | 11.0 | 0.8 | ||||||||||||||||||||||||
Saskatchewan | 2.0 | 0.2 | — | — | — | — | — | — | ||||||||||||||||||||||||
COMPANY TOTAL | 8.0 | 1.1 | — | — | 19.0 | 1.2 | 11.0 | 0.8 | ||||||||||||||||||||||||
Notes:
(1) “Gross Wells” are all wells in which the Company has an interest.
(2) “Net Wells” are the aggregate percentage of Berkley’s interest in Gross Wells.
Oil and Gas Activity
The Company was successful with its 2004 plan to participate in drilling higher interest wells and to sell some of its lower interest properties. In the Brazeau Area of Alberta the Company paid 30% of the well costs to earn 19.50% working interest in a significant natural gas target. The well was completed as a producing gas well and was placed on production during the first quarter 2005. The Company has one smaller interest (6.67%) gas prospect and two additional high-interest, drill-ready projects – one natural gas and one oil – both to be drilled in 2005. The Company holds 35% W.I. in the natural gas prospect and 27.50% interest in the oil prospect. Both can be drilled during the less-busy part of the year making drilling and service equipment costs available at more reasonable rates. Specific projects include:
a)Leduc Area, Alberta
The Wabamun (D-1) gas well “MEC Leduc 11-33-49-26 W4M” has been tied-in and on production since August 6, 2004 at 1.4 million cubic feet per day (1.4 mmcf/d). The Company participated for its 6.67% share to acquire two additional sections adjoining the producing section 33. Berkley holds 6.00% W.I. in the 11-33 gas well through payout, reducing then to 4.00%. Additional wells will be drilled/tested on the acquired lands during the 2nd quarter 2005. This project is expected to make a meaningful contribution to the Company’s cash flow in 2005.
(b)Crossfield Area, Alberta
This natural gas prospect located 50 miles north of Calgary is now ready to drill. The location has been surveyed and the surface lease acquired. Formal licencing procedures will take six weeks to six months to complete as this is a “sour-gas” prospect. Berkley holds 35% working interest in this project, which has as its primary objective, natural gas in the Crossfield formation at a depth of approximately 9,800 feet. Test well drilling costs are estimated at $2,500,000. Berkley’s 35% share will be about $875,000.
(c)Brazeau Area, Alberta
This 11,500’ Nisku formation natural gas well located at 5-13-46-13 W5M in west-central Alberta was spuded on September 14, 2004 and drilled and cased to total depth. The drilling rig was released from contract on November 14, 2004. The “5-13 well” tested natural gas and condensate and was tied-in to the ATCO plant in the area and placed on production February 20, 2005 at four million cubic feet per day (4mmcf/d). The test well was drilled on budget and cost approximately $6,500,000 total when tied-in and placed on production. The Company’s share is 30% ($1,950,000 net). The Company will hold 30% working interest in production from the well through payout reducing then to 19.50%.
(d)Senex Area, Alberta
The Company and its partners have consolidated their acreage holdings at 14 sections (8,960 acres) over this multi-zone prospect which was acquired in a swap of the Skiff Area assets. The acquired properties contained two suspended oil wells which were recompleted and placed on production at an initial monthly average combined rate of over 75 barrels per day (15 barrels net). Three additional wells were drilled and cased in November/December 2004. The Company holds 20% W.I. in two of these new drills and 15% in the third. The Company participated for its 20% share in the 3-D seismic program conducted over the joint lands in January 2005. The seismic program cost $1,700,000 in total ($340,000 net). The 3-D seismic appears very helpful in planning future drilling on this multi-zone prospect.
(e)Sturgeon Lake Area, Alberta
This oil prospect is a well-defined seismic opportunity with projected recoverable reserves of 5 to 10 million barrels. Berkley holds 27.50% working interest in this prospect and it proposes to participate for 15%± of the drilling costs and farmout the remaining 12.50%. The farmee has completed the purchase of 28.25% W.I. from a third party and now has this project drill-ready, with licencing expected for the second half 2005. The Company’s level of participation in the well costs may be influenced by the surface location obtained by the farmee. The much preferred but more difficult to obtain surface location closer to the bottom-hole target (which is under Sturgeon Lake) would see well costs of about $2.5 million. The fallback location which is more distant from the bottom-hole target would see drilling costs projected at $3.1 million.
Forward Contracts and Financial Instruments
Berkley has no forward contracts or financial instruments.
Abandonment and Reclamation Costs
The Company uses its Evaluators to estimate its abandonment and reclamation costs. The costs are estimated on an area by area basis. The industry’s historical costs are used when available. If representative comparisons are not readily available, an estimate is prepared based on the various regulatory abandonment requirements.
The Company has 3.1 net wells for which it expects to incur abandonment and reclamation costs. The total of such costs, forecast net of estimated salvage value, is $67,000 (undiscounted) and $35,000 (discounted at 10%) in respect of proved reserves.
Acquisition, Exploration and Development Costs Incurred
The following table sets out the Company’s property acquisition, exploration and development costs for the fiscal year ended December 31, 2004:
Proved | ||||||||||||||||||||
Property Acquisition | Exploration | Development | ||||||||||||||||||
Unproved | ||||||||||||||||||||
(M$ | ) | (M$ | ) | (M$ | ) | (M$ | ) | Total | ||||||||||||
Alberta and Total: | 137 | 2,369 | 58 | 73 | 2,637 | |||||||||||||||
Production Volume by Area
The following table discloses for each important area and in total, the Company’s production volumes for the financial year ended December 31, 2004 for each production type:
Oil | Natural Gas | |||||||
(bbls) | (mcf) | |||||||
Alberta | ||||||||
Skiff | 1,224 | — | ||||||
John Lake | — | 37,626 | ||||||
Carbon | — | 10,367 | ||||||
Leduc | — | 9,263 | ||||||
Senex | 1,256 | — | ||||||
Halkirk | 218 | 4,969 | ||||||
Minor | — | 642 | ||||||
2,698 | 62,867 | |||||||
Saskatchewan | ||||||||
Dollard/Success | 8,181 | 1,019 | ||||||
Company Total | 10,879 | 63,886 | ||||||
4