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Pine Point Formation Is Stratigraphically Equivalent to the Keg River Formation

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Pine Point Formation Is Stratigraphically Equivalent to the Keg River Formation Page: 1 of 71 EKWAN PIPELINE INC. GAS RESOURCE AND SUPPLY STUDY NORTHEASTERN BRITISH COLUMBIA Effective January 01, 2003 1035834 Gilbert Laustsen Jung Associates Ltd. Page: 2 of 71 GAS RESOURCE AND SUPPLY STUDY TABLE OF CONTENTS Page TRANSMITTAL LETTER 3 INTRODUCTION 4 SUMMARY 5 DISCUSSION 8 PLAY TYPES 17 GAS SUPPLY FORECASTS 27 MAPS 28 PLOTS 33 TABLES 55 REFERENCES 71 Gilbert Laustsen Jung Associates Ltd. Gilbert Laustsen Jung Associates Ltd. Petroleum Consultants 4100,400 - 3rd Avenue S.W.,Calgary,Alberta,Canada T2P 4H2 (403) 266-9500 Fax (403) 262-1855 March 14, 2003 Project 1035834 Mr. Cameron Buss, P. Eng. EnCana Corporation 2900, 421 – 7th Avenue S.W. Calgary, Alberta T2P 4K9 Dear Mr. Buss: Re: Northeastern British Columbia Gas Resource and Supply Study As requested, Gilbert Laustsen Jung Associates Ltd. has completed a study of the natural gas resource and supply potential of Northeastern British Columbia. The attached report summarizes analysis methods and conclusions of this study. We trust that this report meets your current needs. Should you have any questions or comments relating to this matter, please contact Dave Harris at (403) 266-9588 or Harry Jung at (403) 266-9505. Yours truly, GILBERT LAUSTSEN JUNG ASSOCIATES LTD. ORIGINALLY SIGNED BY David G. Harris, P. Geol. Vice-President, Geosciences ORIGINALLY SIGNED BY Harry Jung, P. Eng. Executive Vice-President HJ/DGH/jem Attachments Page: 4 of 71 INTRODUCTION Gilbert Laustsen Jung Associates Ltd. (GLJ) was requested by Ekwan Pipeline Inc. (Ekwan) to prepare a study of future gas supply from a portion of Northeastern British Columbia. The study area, hereinafter referred to as the Ekwan Study Area, encompasses approximately 11,800 square miles, as illustrated on Map 1. The primary objective of the study was to provide information regarding regional near-term to medium-term gas supply potential in support of the proposed construction of the Ekwan Pipeline. A twenty year gas supply forecast effective January 1, 2003 was requested. Gas forecasts were to be expressed as a range based on proved, probable and possible reserves categories and undiscovered resources classified as low estimate, best estimate and high estimate categories. The Petroleum Society of the Canadian Institute of Mining, Metallurgy and Petroleum (CIM) definitions of reserves and resources were to be used as the basis of reserves and resources classifications. Historical drilling activity and production rates and the near-term drilling plans of EnCana Oil and Gas Partnership (EnCana O&G) were to be considered in preparing forecasts of development and production. Future gas production projections were to assume no constraints on demand or limitations in gas transmission capacity. Gilbert Laustsen Jung Associates Ltd. Page: 5 of 71 SUMMARY This report provides forecasts of natural gas supply for the general area to be served by the proposed Ekwan Pipeline. Data used in the preparation of this report was obtained from the National Energy Board (NEB), the British Columbia Oil and Gas Commission (BCOGC) and other sources of published data, information available from EnCana O&G and the non-confidential files of GLJ. For this analysis, general well and production data was available to approximately November 30, 2002. A primary source of base estimates for discovered reserves was the “Hydrocarbon and By-Product Reserves in British Columbia”, December 31, 2001 (Ref 1), published by the British Columbia Oil and Gas Commission (BCOGC), and the associated Petroleum Information Management System (PIMS) databases. Total reserves and production for British Columbia and estimates extracted for the study area are as follows: Total Marketable Gas (BCF) at December 31, 2001 Initial Cumulative Remaining Reserves Production Reserves Total BC 23,537 14,587 8,950 Study Area 4,897 3,376 1,521 The foregoing indicates that the study area comprises approximately 17 percent of British Columbia’s total remaining marketable gas reserves. GLJ reviewed and updated these base discovered reserves estimates for the study area incorporating more recent drilling and well performance data. GLJ’s estimated reserves (BCF) at January 1, 2003 is as follows: Cumulative Estimated Initial Raw Gas Remaining Remaining Raw Gas Reserves Production Raw Gas Reserves Sales Gas Reserves Proved Pv+Pb Pv+Pb+Ps Proved Proved Pv+Pb Pv+Pb+Ps Proved Pv+Pb Pv+Pb+Ps 6,744 7,415 7,812 4,657 2,087 2,758 3,155 1,779 2,388 2,745 Pv = Proved; Pb = Probable; Ps = Possible Gilbert Laustsen Jung Associates Ltd. Page: 6 of 71 The Jean Marie Formation has been mapped over a large portion of the study area, however, reserves were only assigned to accumulations near existing development or where wells have been tested at commercial rates. Jean Marie reserves estimated to be potentially recoverable from known accumulations that have not been proved commercially recoverable or where evaluation of the accumulation is still at an early stage are classified as contingent resources. GLJ’s estimate of contingent resources (BCF) at January 1, 2003 is as follows: Contingent Resources Marketable Gas Resources (BCF) Low Estimate Best Estimate High Estimate 234 401 621 GLJ performed a regional geological review of the hydrocarbon systems in the study area. Studies addressing undiscovered reserves potential prepared by the NEB were also reviewed. GLJ estimates the following total undiscovered marketable gas resource potential at January1, 2003 for the area: Estimated Undiscovered Marketable Gas Resources (BCF) Low Estimate Best Estimate High Estimate 514 1,011 1,623 Resulting total remaining reserves plus resources in the study area as at January 1, 2003 are estimated as follows: Estimated Total Marketable Gas Resources (BCF) Low Estimate Best Estimate High Estimate 2,527 3,800 4,989 Total production from the area, as illustrated on Plot 1, has generally followed a gradually increasing trend in the past 20 years and averaged 590 MMCFD raw in 2002. Production of the developed estimated reserves was forecast based on existing decline trends. Forecasts of future production from undeveloped reserves and undiscovered resources were prepared giving consideration to historical discovery rates and drilling activity. Gilbert Laustsen Jung Associates Ltd. Page: 7 of 71 Table 1 presents a summary of reserves and resources in the study area and recent Table 2 illustrates historical and forecast production for the study area for various certainty levels. Details regarding the derivation of estimates of reserves and resource supply potential are provided in the “Discussion” section of this report. Gilbert Laustsen Jung Associates Ltd. Page: 8 of 71 DISCUSSION Established Reserves The Ekwan Study Area contains a significant portion of British Columbia’s total established (i.e. discovered) natural gas reserves and remains active for natural gas development and exploration. Approximately 2,400 wells have been drilled to date in the area. A total 1,023 well- zones have produced gas, and 615 wells are currently producing at a total raw gas rate of approximately 600 MMCFD. The major identified gas reserves and producing horizons are the Jean Marie, Mississippian- Debolt, Pine Point and Slave Point. The following table summarizes average 2002 production by zone: Raw Gas Zone (MMCFD) Jean Marie 263 Mississippian-Debolt 56 Pine Point 202 Slave Point 52 Other Zones 17 Total 590 Reserves (Excluding the Jean Marie Zone) The initial review of zones other than the Jean Marie relied on the BCOGC Petroleum Information Management System (PIMS) database effective December 31, 2001 as a starting point for reserves estimates. Table 3 presents a summary of BCOGC reserves for each of the pools identified in the study area along with other pertinent information such as well counts, production and discovery date. Recent production and pressure history data was reviewed for all of the major pools in each horizon. Remaining reserves were estimated for each pool and classified as proved, probable and possible. The BCOGC initial reserves figures were adopted as initial proved reserves where there was a very good agreement of the BCOGC estimates with existing performance. Where current information warranted, reserves estimates were varied from the BCOGC figures. Proved, proved plus probable and proved plus probable plus possible reserves were assigned as considered appropriate based on uncertainties in the reserves interpretation. Gilbert Laustsen Jung Associates Ltd. Page: 9 of 71 Plots 2 to 5 present examples of the reserves estimates for one of each of the largest reserves entities in the Debolt, Pine Point, Slave Point and “Other Zones” groups. Jean Marie Reserves A more detailed discussion on the geology of the Jean Marie play is presented later in the report, in the section discussing “Play Types”. In order to address the discovered reserves in the Jean Marie, the net gas pay and net pore volume maps that were generated as part of the geological study were used to determine the “best estimate” net rock volume and average porosity for each block in the study area. The study area is comprised of 454 blocks averaging 16500 acres for a total area in the range of 7,491,000 acres. For reserves determination purposes the study area was subdivided into eight regions (Map 2) based primarily on geological and performance characteristics. EnCana O&G and BCOGC area definitions were also taken into consideration when dividing the study area into regions. Reserves are listed by classification on Table 4. The net rock volume and the net pore volume for each block were generated electronically from the digitized mapping. The average net pay and porosity by block were then calculated from these volumes. The water saturation was then determined for each block based upon a regional review of the bulk volume of water constant (phi*Sw). This value typically varied between 0.02 and 0.0175, giving water saturations of 38 to 33 percent at the average regional porosity of 0.052.
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