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EKWAN PIPELINE INC.

GAS RESOURCE AND SUPPLY STUDY NORTHEASTERN

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, 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

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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.

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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

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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.

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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.

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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.

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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. Reserves were removed for blocks with average calculated water saturation greater than 50 percent. This had a minor impact as it affected only 2 percent of the mapped OGIP. Two blocks with a water saturation slightly higher than 50 percent were not removed due to demonstrated productivity. Average initial pressure, temperature and compressibility were estimated for each of the blocks. Regional averages were applied to each of the blocks for the most part except for some selected areas. Initial average reservoir pressures used in this evaluation range from 875 to 2000 psia.

The volumetrically determined original gas-in-place (OGIP) for each block was then reviewed specifically for risk. For example, a block directly offsetting existing production would be far more likely to be in a successful producing area than a block in the south portion of the study area where there is essentially no gas production. Thus, much of the OGIP in the south region was considered to be high risk and was therefore only included in the “possible reserves” classification or categorized as a resource. The “proved,” “proved plus probable” and “proved plus probable plus possible” estimates where then derived from the summation of the blocks with similar perceived risk and totalled by region.

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Reserves potential classifications were assigned to each block. A proved classification was assigned to blocks with demonstrated productivity. Offsetting blocks that have not been proved commercially productive, but with sufficient well control to map OGIP volumes were classified as probable. Possible reserves were addressed using an increased recovery factor assignment, except for in the Conroy Area. Cumulative gas production and recent production rates were tabulated for each block. A bubble map of cumulative production was superimposed on the net gas pay map as an aid in the block classification. A total of 90.5 blocks were classified as proved and an additional 34.5 blocks as probable. Given the relatively large average block area of 16500 acres, partial block classifications were often used. For example a block may be classified as 50 percent proved and 50 percent probable. OGIP volumes of 2337 BCF, 3146 BCF and 3264 BCF were assigned in the total proved, total proved plus probable and total proved plus probable plus possible cases, respectively.

Proved producing, proved plus probable, and proved plus probable plus possible reserves were assigned by a combination of decline analysis and volumetric calculation. Group production history and forecasts for the Jean Marie Formation are presented as Plots 6 and 7. Jean Marie wells were grouped into the eight regions (six regions assigned producing reserves) for the decline analysis review. Recovery factors were assigned by region for each of the three reserves categories. The recovery factor assignments are based on decline analysis of the historical decline trend and consideration as to recoveries typically observed for each region. This analysis results in total producing recovery factors of 57, 61 and 65 percent for the three respective reserves categories. These recovery factors are based on the total proved OGIP of 2337 BCF, as producing reserves were not assigned to probable nonproducing and possible nonproducing volumes. Ultimate raw reserves of 1326 BCF, 1415 BCF and 1510 BCF were determined for each of the respective reserves categories.

Nonproducing reserves were assigned volumetrically by applying recovery factors on a regional basis. These recovery factors were applied to total proved, probable and possible OGIP volumes. The OGIP for the Conroy area is classified as possible. Proved nonproducing reserves are calculated using the ultimate total proved reserves less the producing component. Ultimate raw gas reserves of 361 BCF, 817 BCF and 1011 BCF are assigned in the proved nonproducing, proved plus probable nonproducing and total proved plus probable plus possible nonproducing cases, respectively. An average surface loss of 6 percent was assigned to all areas.

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Reserves were assigned to 125 of the 445 blocks in the study area. GLJ has analyzed the reserves potential for the remaining 329 blocks. Contingent resources were assigned to 85 Blocks in close proximity to existing development. Resource potential for these blocks was calculated using OGIP volumes generated in the reserves analysis. An additional 216 blocks are considered to have lower reserves potential and there are 29 blocks located to the west of the reef trend with no Jean Marie reserves potential. Contingent resources and undiscovered resources are discussed in the following section of this report.

Undiscovered Resources

The following review of the basic geological processes that result in the creation of hydrocarbon traps provides useful background information that may assist in understanding estimates of resource potential. In order for a hydrocarbon reservoir to exist, there are eight geological prerequisites that must be fulfilled. The total risk associated with an individual prospect or play is directly related to the risk the GeoScientist places on each of the eight processes. If the first wells in a new play are abandoned, it is critical to understand the reasons behind the failure. If the geological process that failed is related to that specific target, it has far fewer implications to the play as a whole than if the geological process that failed relates to the generation and migration of hydrocarbons. The lack of a mature source rock or a viable migration path immediately impacts upon the prospectivity of the entire play, and possibly the basin as a whole.

Source Rock

A source rock contains organic matter that will generate and expel hydrocarbons under the correct temperature conditions. Common source rocks include shales and argillaceous . The type of organic matter, or kerogen, and the temperature influence the type of hydrocarbon generated and expelled by the source rock. Type I kerogen, also known as algal or sapropelic organic matter, is a kerogen that is derived from marine environments, and will generate oil under the correct temperature conditions. Type III kerogen, often referred to as woody, coaly or humic organic matter is derived from terrestrial regions, and will generate natural gas under the correct conditions. Another kerogen, called Type II, is derived from herbaceous or fibrous plant material, and will generate waxy crudes and natural gas.

The amount of kerogen in the source rock, measured and reported as the total organic carbon, or TOC (in percent), and the temperature regime influence the amount of hydrocarbon that can be generated per unit volume of source rock. The product of the hydrocarbon generating capacity (related to TOC) of the source rock and the volume of the source rock that has been

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exposed to the correct temperature regime will determine the potential volume of hydrocarbon expelled by that source rock in that basin. The most productive basins will generally have multiple source rocks.

Temperature History

The source rock must be heated in order to generate hydrocarbons. This occurs as a result of increasing burial depth. Generally, kerogen will start to produce hydrocarbons at a temperature of about 60 degrees Celsius, with peak generation in the range of 80 to 90 degrees. At temperatures above 160 degrees Celsius, the source rocks are over mature and will generally produce methane only.

Due to highly variable thermal gradients in different basins, the top of the hydrocarbon generation window, defined by the elevation of the 60 degree isotherm, is highly variable. However, at normal geothermal gradients, the top of the generation window occurs between 7000 and 12,000 feet.

Migration Paths

The hydrocarbons generated by the source beds must have a migration path away from the source rock to the reservoir rock. Hydrocarbons move toward higher regions due to buoyancy. Common avenues of migration include carrier beds that are regional permeable layers that are in contact with the mature source rock and are capped by impermeable top seals, and large faults that pass through both the mature source rocks and the reservoir rocks.

Reservoir Rock

There must be a porous and permeable reservoir rock that would permit the accumulation of hydrocarbons. Frequently, the reservoir rock is the same as the carrier bed.

Seal

All hydrocarbon traps need an unfractured, impermeable layer overlying the reservoir. Some examples of this are shale beds or evaporite layers. This “top seal” prevents the upward migration of hydrocarbons out of the trap. In stratigraphic, combination, or fault-related traps, lateral seals also exist.

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Trap

In the case of structure traps, the reservoir rock must exist in a configuration that prevents the lateral migration of hydrocarbons. This can be formed by four-way dip closure such as that observed in a dome or double plunging anticline, or by dip closure against sealing faults.

Timing

All of the above must occur in the correct time sequence. The hydrocarbons must be expelled after the creation of the migration paths, the reservoir rock, the top seal, and the establishment of the correct reservoir configuration.

Preservation

The hydrocarbons must be preserved from destruction and contamination. This can occur due to the introduction of bacteria that can biodegrade the hydrocarbons, or due to the later entrapment of acid gases, or excessive heating of the reservoir.

Methodology

The undiscovered resource potential of geologically prospective areas can be assessed using a variety of methods. It should be noted that a common aspect of these analyses is to define the exploration play as a family of pools and/or prospects and leads that share a common history of hydrocarbon generation, migration, reservoir development and trap configuration (page 11, reference 2). In other words, the prospects within the exploration play should have common geological characteristics.

The three most common methods in use today are:

1) Petroleum systems analysis - This is a largely theoretical exercise that is often applied in very immature basins that have very little physical data. Regional geological studies, including surficial mapping and a few wells, and regional scale geophysical interpretations are utilized in an attempt to define the petroleum system and the types of traps. Attempts are made to define the number of traps that might exist, and the potential amount of hydrocarbons in place per structure. The analysis can be fairly straightforward; the number of structures is multiplied by a success rate (geological risk) multiplied by the volume of sales gas per discovery gives an estimate of the ultimate potential.

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Other, more detailed analysis can be conducted. There are computer programs, such as the Arps-Roberts Discovery Process Model or Delphi Method utilized by the Canadian Gas Potential Committee (CGPC, reference 3), that take into account drilling results in one area of the basin, then mathematically apply it to the untested regions. The National Energy Board uses a similar approach, utilizing the @Risk simulation software, in evaluating less well developed areas of somewhat mature plays as well (reference 4). The simulation then gives a probability distribution of the ultimate resource potential.

2) Statistical methods – Most recent evaluations of ultimate resource potential in mature basins, including those of the Geological Survey of Canada (GSC, reference 2) and the CGPC (reference 3), rely upon statistical methods, such as the discovery process model (PETRIMES). These utilize plots that rank pools by size. Studies of very mature basins have indicated that pool size populations, grouped by play type, typically have a lognormal distribution. Therefore, in the absence of maturity, a plot of pool rank by size represents an incomplete dataset, with typically a disproportionate number of the larger reservoirs present. The discoveries describe a population that can be infilled with “undiscovered reservoirs” in order to create a reasonable, smooth logarithmic distribution. The result is a description of both the number and the size of undiscovered reservoirs. This method is aided when a reasonable estimate of the number of discoveries remaining can be made.

3) Drilling exhaustion analysis - In simplified terms, this method estimates the undiscovered resource potential by extrapolating the hydrocarbon reserves per unit of the drilled area to the undrilled area. The application of this method is now uncommon and is limited to very mature areas. It is limited in that the method gives little or no description of the number or size distribution of the undiscovered resources.

The maturity of the play dictates the method that is employed. There are a few terms that have been historically employed in describing the maturity of a play:

Established Plays

This is an exploration play that has been demonstrated to exist by virtue of discovered pools with established reserves (page 11, reference 2). A further subdivision can be made into immature Established Plays, with only a few discoveries, and mature Established Plays, where there are many discoveries.

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Mature established plays can be analyzed statistically, whereas immature established plays will often require some form of petroleum systems analysis.

Conceptual Plays

This is a play that does not yet have discoveries but which geological analysis indicates may exist (reference 2 and 3). Assessment of undiscovered resources in this instance is characterized by a high degree of uncertainty (the lack of discoveries vastly increases risk associated with source, maturity, and migration paths versus the immature established play). The petroleum systems analysis can be used in this case.

Subject Area

The subject area covers approximately 11,800 square miles, and contains approximately 2393 first event wells. This figure includes 669 horizontal wells, leaving 1724 vertical and deviated first event sequence wells, or about 1 well per 6.8 sections. GLJ has noted about 907 wells that were licensed as exploration wells (New field wildcat, New pool wildcat and Outpost), indicating that there has been one exploration well drilled per 13 sections. These figures suggest that there should be reasonable exploration upside in the subject area.

Reserves figures obtained from the BCOGC (reference 1) and regional geological studies by the GSC (reference 2) have indicated that there are seven main play types in the subject area. In descending order of identified reserves level, these include the Pine Point Yoyo play, the Jean Marie Formation, the Slave Point Clarke Lake play, the Slave Point Adsett play, Pine Point July Lake, and the Debolt and Bluesky Formations.

The undiscovered potential in six of the seven main plays in the subject area were analyzed using statistical methods, with original gas-in-place figures derived from the BCOGC (reference 1). GLJ has not had access to regional studies over the area of interest that might provide some insight into the number of targets that remain in each of the above noted plays. Therefore, GLJ has determined both a low and a high estimate using pool size by rank plots, and has then provided a best estimate based upon geological judgment and recent drilling results.

The largest play in the subject area (in terms of undiscovered potential), the Jean Marie, has been mapped using wellbore parameters determined by both GLJ and EnCana O&G, with final

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volumes determined by applying a risk factor that takes into account proximity to known production.

Additional gas plays that exist in the Baldonnel, Banff, Detrital, Doig, Dunvegan, Kakisa, Montney, Pekisko, Shunda and Sulphur Point have not been evaluated for this report. The volume of gas discovered to date in these plays is minor in comparison to the zones that were analyzed, and therefore would likely need to be analyzed using conceptual models. While upside may remain in these zones, it is interpreted that this will be relatively small.

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PLAY TYPES

Bluesky

The covers virtually the entire area of interest. It is a somewhat complex formation, with the lowermost section of the formation deposited in a series of coarsening upward sequences typical of offshore to shallow marine settings. Later depositional layers have been identified as transgressive lags associated with the encroachment of the Boreal Sea. Both of these layers can be eroded by incised valley’s, which were then infilled with a third, distinct Bluesky sequence. Gas entrapment in the Bluesky of Northeast British Columbia is typically caused by a combination of structural closure and stratigraphic changes. Lateral seals can also be provided by bitumen saturation.

According to the BCOGC (reference 1), drilling to date in the area of interest (Map 1) has resulted in the discovery of 52.7 billion cubic feet (BCF) of original-gas-in-place within 13 reservoirs (including D-95-E/94-I-15, which is listed in the hard copy). The last discovery was in December of 1999 (Sierra Bluesky), and there are currently 10 Bluesky production entities in “Other Areas”, as shown on Table 3. These were drilled in the last two years, and as such have not had reserves assigned to them. This suggests that this is a relatively active play, which is understandable since this zone is relatively shallow and will therefore be penetrated by most wells in the region.

Two pool rank by size plots have been created for the Bluesky play. These graphs, included herein as Plots 8 and 9, provide a high estimate and a low estimate for the undiscovered original gas-in-place, respectively. A reasonably optimistic interpretation of the distribution suggested by the discoveries made to date allows for five remaining large discoveries with OGIP varying between 8.0 and 2.8 BCF, and an additional 41 smaller reservoirs. This high case suggests a remaining undiscovered OGIP of 67 BCF. The low estimate assumes that there are no large reservoirs left to discover (>2.4 BCF), and uses the steepest reasonable slope on the rank by size plot to estimate the number of smaller reservoirs left to discover. The low case presented on Plot 8 suggests that there are 28 pools to be found (limited at an OGIP of >= 400 MMCF) with a total OGIP of 30 BCF.

Given the fact that the play area covers virtually the entire area of interest, that the Bluesky is the stratigraphically highest zone among the major plays (and will therefore be penetrated by the vast majority of the wells drilled in the future) and given the number of Bluesky entities declared in the last two years, GLJ believes it is reasonable to utilize the high case as the best estimate.

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Debolt

The subject area is situated along the erosional subcrop of the Mississippian age Debolt Formation, with only the Northeast region (approximate Northeast and east portions of 94-P, and parts of 094-I-9 and 094-I-16) considered nonprospective due to complete erosion of the Debolt. The Debolt carbonate is quite thick, resulting in a very wide erosional subcrop. This feature, when combined with multiple porous layers within the Debolt results in the creation of a great variety of traps, ranging from two and three way structural closure against erosional promontories in the Mississippian subcrop, to simple four way structural closures and stratigraphically sealed erosional outliers. Reference 5 states that these reservoirs have typically “…undergone diagenesis along their eastern subcrop edges to produce reservoirs with vuggy, pinpoint, and intercrystalline porosity” (pg. 26).

The discoveries that have been made to date in the area of interest are listed on Table 3. Nineteen reservoirs are estimated to contain an original gas-in-place of 80.4 BCF, with four recent reservoir entities lacking an OGIP determination. The high estimate and the low estimate size by rank graphs for the Debolt are presented as Plots 10 and 11, respectively. The high estimate plot recognizes the potential for undiscovered large pools and used a slope that is somewhat steeper, but reasonably consistent with the slope suggested by the discoveries made to date. Note that the high estimate includes an undiscovered pool that is larger than anything found to date (OGIP of 50 BCF). GLJ notes that the Thetlaandoa Debolt A Pool was assigned an OGIP of only 11.3 BCF in the year end 2001 reserves database. However, production data clearly indicates that this pool is substantially larger than this, (currently producing approximately 51 MMCFD with a cumulative gas production of over 20 BCF), indicating that large reservoirs can exist in this formation. This analysis gives a high estimate of 86 remaining reservoirs with a combined OGIP of 165 BCF.

The low estimate utilized the slope of the largest discoveries made to date to estimate the size of one pool that exceeds anything yet discovered (Plot 11), and a slope that is steeper than used in the high case estimate. This graph resulted in the interpretation of 61 remaining pools with a combined OGIP of 104 BCF.

Given the large play area of the Debolt and the number of different zones within the Debolt that can be targeted, GLJ believes that the high estimate presents a very reasonable interpretation of what remains to be found. However, this is tempered in the best estimate due to slow rate of reserves addition in the last few years of the 1990’s (one discovery in 1999 preceded by two in

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1998, two potential discoveries in 2000). GLJ is aware that this may not be a lack of success as much as a dominant focus on other horizons.

Jean Marie

The Jean Marie Formation is a unit deposited on a shallow marine shelf. In the Eastern portions of the study area typified by the Helmet, Peggo, July Lake, Midwinter and Ekwan fields the Jean Marie ranges in thickness from 17 to 24 metres. In the Gunnell/Cabin trend the Jean Marie can attain a thickness of up to 75 metres. Reservoir development in the Jean Marie is related to localized reef stromatoporoid and algal mounds and secondary intercrystalline porosity, enhanced in some regions by a regional fracture system.

The best reservoir facies is distributed in a general north-south trend approximately two miles wide on the western boundary of the study area. This represents a barrier reef morphology. A lateral change to tight limestone occurs on the west edge of this trend where it is possible that subsidence was slow enough for additional Jean Marie deposition but was too rapid for shallower water reefal organisms to remain established. Further to the west into the Otter Park/Besa River shale basin the Jean Marie carbonate becomes less recognizable as a potential reservoir unit. To the east of the barrier trend, towards the Ekwan and Helmet type areas, the Jean Marie becomes more platformal and can have lower average thickness and porosity. This represents widespread deposition over the larger regional Devonian carbonate bank. Topography on the underlying middle Devonian carbonate buildups is likely to have had some influence on the distribution of the subsequent shoaling facies of the Jean Marie. It is also possible that regional basement tectonics could have influenced porous Jean Marie facies distribution, as well as later fracture development and its corresponding reservoir enhancement.

Vuggy porosity is the dominant pore type in the algal and stromatoporoid boundstone facies, whereas intercrystalline porosity can tend to be more common in the carbonate mudstones. Relative amounts of intercrystalline versus vuggy porosity types appears to have a bearing on the initial productivity and production profile for wells completed in the Jean Marie for gas. Vertical and oblique fractures are frequently encountered in cores, with the productivity of some wells suggesting a well-developed natural fracture system in some areas.

The Jean Marie reservoir is underpressured, and therefore, is subjected to wellbore damage by the drilling fluid. A low initial flow rate from a drill stem test (DST) or production test, especially in a deep well without core data in the Jean Marie, can easily be given up as a poor well. Correct identification of facies from logs and/or sample cuttings, proper completion and stimulation can

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often return the well to a productive state. Most of the newer wells targeting the Jean Marie are being drilled underbalanced, horizontally to avoid formation damage and to better access the lower porosity/permeability gas charged rock layers.

Regionally, both EnCana O&G and GLJ determined wellbore parameters by applying cutoffs of 3 percent porosity and 0.1 millidarcy (md) permeability where core was available. EnCana O&G supplied wellbore parameters for 964 wells in the subject area, of which 464 had a net pay greater than zero and had been previously evaluated by GLJ. Although there is the rare well that had a significant difference, the average pore volume for these wells is calculated at 0.425 metres by EnCana O&G, versus 0.424 by GLJ. A comparison of the data indicates that 68 percent of the wells had pore volumes that were less than 0.15 metres different. This suggests that while the net pay and pore volume maps that would be created independently by GLJ and EnCana O&G would vary in some areas, the final OGIP calculated from both maps would be very close.

GLJ generated a regional net gas pay map using wellbore values and interpretations that were generated in earlier studies, augmented by EnCana O&G wellbore values where GLJ had not conducted a previous study (generally, these are located in areas that are not in close proximity to production). The final map was based upon 1285 wells, including control wells situated in the regions just offsetting the area of interest. The zero edge’s of the resulting net pay map are shown on Map 2. Please note that there are significant regions of this map that contain net gas pay that is not in close proximity to known production and therefore is deemed to be quite risky as a region for commercial development. The total OGIP as presented on Map 2 is approximately 6 TCF. However, as was discussed in the established reserves section, GLJ has taken risk into account before calculating the final OGIP volumes for the Jean Marie play.

For this study connate water saturations used in Jean Marie OGIP calculations were assigned to individual regions using Bulk Volume Water (BVW) constants divided by the average porosity determined for each block. Maintaining consistency in the calculations of connate water saturations, based on standard log analysis techniques over an area as large as the study area can be problematic. This is based in part on the lack of a significant number of reliable produced water samples available for water resistivity (Rw) measurements. The lowest Canadian Well Logging Society Catalog Rw value published for the Jean Marie in the area is 0.126 ohm-metres at 25 degrees Celsius. The highest value is 0.451 ohm-metres. The 0.126 value would yield a minimum Rw at formation temperature = 0.055 for the area. As the Jean Marie does not produce at water cuts indicative of a gas zone with saturations above irreducible, any produced water samples collected could be a combination of formation water and fresher water of condensation. Given that actual produced Devonian waters in the area, such as water from the Slave Point, are

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typically closer to 0.06 ohm-metres at 25 degrees it is not unreasonable to suspect that the actual Jean Marie water Rw is closer to this value. This yields a minimum Rw @ FT closer to 0.034 ohm.metres. Water saturations calculated using a, m, and n values of 1, 2 and 2 respectively and water resistivities from 0.055 to 0.034 obviously yield a wide range of values. Water saturations calculated in this manner range from 13 percent to over 60 percent for porosities greater than 3 percent.

Typically bulk volume water (BVW) constants determined from wellbore average porosity and water saturation values range between about 0.02 and 0.0175. The higher saturations or bulk volume water values that are frequently calculated in some areas and/or lithologic layers of Jean Marie deposition are likely due to textural variations of the rock present, for example tighter micritic limestone. Attempts have been made to determine the water saturation using a variety of special core studies. Indications from these studies are that irreducible water saturations may be lower than presently calculated. However, additional work may be needed to confirm lower water saturation values. In addition, future well performance may dictate that lower water saturation values be recognized. A wide variety of a, m and n values would be needed to quantify connate water saturations more exactly using log analysis techniques throughout the study area. This would take into account the varying reservoir and non reservoir rock types of the Jean Marie. At the time of this report, these studies are still in a preliminary stage and much more work needs to be done before any conclusions can be reached.

The choice of actual BVW constant assigned to particular blocks or regions was based on a consideration of typical reservoir production performance, conventionally calculated water saturations, and relative amounts of reservoir rock within the higher and lower porosity ranges above the 3 percent porosity cutoff. The basic premise was to attempt to account for the correlation between rock type or texture and irreducible connate water saturation.

As indicated previously, both contingent and undiscovered resources have been assigned to the Jean Marie Formation. A total of 125 blocks with mapped Jean Marie pay were classified as proved, probable or possible. Proved, probable and possible reserves were assigned to these lands. Possible reserves assignments were addressed primarily using increased recovery factor assignments. Contingent resources were assigned to blocks located in close proximity to areas classified as proved or probable where there is sufficient well control to map OGIP volumes, but considerable uncertainty associated as to the productive potential. A total of 85 blocks were assigned contingent resources. OGIP volumes for all blocks assigned contingent resources were totaled by region. The uncertainty associated with successfully drilling and developing the contingent OGIP volumes was addressed by assigning a probability of success by region.

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Successful exploitation for all regions, except Conroy, is estimated at 30 percent, 50 percent and 40 percent for the low estimate, high estimate and best estimate, respectively. Contingent resources were not assigned to the Conroy region in the minimum case and the best estimate was reduced to 25 percent to account for the higher uncertainty associated with the resource potential in this area. Regional average recovery factors observed for the proved, proved plus probable and proved plus probable plus possible reserves categories were applied to the OGIP volumes. Using this approach, ultimate contingent resources (raw) of 249 BCF, 661 BCF and 427 BCF were assigned as the low estimate, high estimate and best estimate, respectively.

There are an additional 216 blocks within the Jean Marie trend with resource potential. The Jean Marie Formation in these blocks has not been mapped or the mapped OGIP volumes and reserves potential is uncertain due to a lack of well control and test data. The undiscovered resource potential was based on the regional average per block ultimate reserves assignments determined for the proved reserves and contingent resource lands. Blocks with undiscovered resource potential were totaled by area. The probability of finding significant undiscovered resources in the study area is high, as the Jean Marie Formation has been identified to exist depositionally across the study area. As a result, the best estimate of the probability of discovering a block with average resource potential is 30 percent for all regions except Conroy and Ekwan, which were reduced to 20 percent. The minimum and maximum estimates are 10 percentiles lower and higher than the best estimate. The best estimate of undiscovered Jean Marie resource potential for the study area is 604 BCF (raw) with a minimum estimate of 328 BCF (raw) and a high estimate of 1010 BCF (raw).

Slave Point – Adsett Play

The Slave Point Adsett play area covers about three quarters of the study area (Map 3). These reservoirs are formed by gas entrapment within dolomitic zones that are believed to be of hydrothermal origin. It is interpreted that hot, magnesium-rich fluids migrated vertically along fault planes or fracture zones associated with regional trends or with differential compaction around the underlying Keg River carbonates. After vertical movement, any horizontal or near- horizontal permeable zone may provide an additional migration path for these fluids, allowing more areally extensive dolomitization.

The first discovery made in this play occurred in early 1960’s, in the Junior field (Table 3), with the latest discovery drilled in 1996 (Sextet Slave Point D). It is interesting to note that this latest discovery is also the third largest reservoir discovered to date, with an OGIP of over 49 BCF. The largest discovery made to date is the Helmet Slave Point A Pool, with an OGIP of about 242 BCF

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(Table 3). To date, 29 reservoirs have been discovered in this play, containing an OGIP of 672 BCF. There are two Adsett Slave Point production entities declared for wells drilled in early 2002.

The high estimate size by rank plot utilizes the shallower slopes suggested by the discoveries made to date, resulting in 65 additional pools with a combined OGIP of 352 BCF (Plot 12). It is noted that the slope is still somewhat steeper than could be interpreted for this distribution, and that a break-in-slope is still present, however, the lack of recent discoveries in this play suggests that the hundreds of pools that would be necessary in order to infill the plot in order to form a linear function is not supportable.

The low estimate pool size by rank plot is presented as Plot 13. This interpretation honours the steeper slopes and infills the graph with as few discoveries as is reasonably possible to arrive at a conservative distribution. This provides a low estimate of an undiscovered OGIP of 159 BCF contained within 41 reservoirs. GLJ has used 50 percent of the high case as a best estimate, resulting in an expected undiscovered OGIP of 256 BCF.

GLJ notes that the GSC is considerably more optimistic on the upside of this play (Table 11, pg 112 of reference 2). The GLJ interpretation is tempered by the pace of discovery.

Slave Point – Clarke Lake Play

Porosity associated with the reef margin facies of the Slave Point carbonate bank (Map 3) can be selectively dolomitized. Like the Adsett play, hydrothermal fluids may again control dolomitization, such that the reefs that are in close proximity to faults or fractured zones may have a higher probability of being dolomitized. Although a large part of the Clarke Lake play area is contained in the area of interest, the play area itself is fairly narrow.

There have been 42 discoveries in this play in the study area, containing an OGIP of about 1198 BCF. The last of these discoveries was the Louise Slave Point B Pool, drilled in March of 1995. Although there has not been a discovery since that date, GLJ notes that there are six production entities dating from 2001 and 2002 that might suggest some more recent success.

In the high estimate (Plot 14), large (up to 87 BCF) to medium sized undiscovered pools are possible. The slope through the medium to small sized pools is somewhat shallower than interpreted in the low estimate (Plot 15), though a shallower slope could still be interpreted. This graph results in an undiscovered OGIP of 601 BCF in 69 reservoirs. Plot 15 is the low estimate

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pool size by rank plot for the Clarke Lake play. In this plot, a reasonable but fairly steep slope through the medium to small size pools is used to infill the distribution. This results in an undiscovered OGIP of 274 BCF contained in 45 reservoirs.

Given the narrow trend of this play, GLJ has utilized the low estimate as the best estimate.

Pine Point, July Lake Play

The is stratigraphically equivalent to the . However, the upper portion can be considerably thicker, extending upward into the base of the Sulphur Point/Slave Point sequence. For simplicity sake, the regionally developed carbonate platform that forms the lower section is often referred to as the Lower Keg River, whereas the reefal, dolomitized section that can extend well above the basal unit has been referred to as the Upper Keg River.

In the area of the Cordova Bay (see Map 4), deep marine conditions prevented the growth of the reefs that eventually formed the Upper Keg River. In this area, thick deposits of shale (known variously as the Evie, Horn River and Klua Formations) replace the carbonate, forming an effective seal on the underlying Lower Keg River (reference 1). In this setting, porosity developed in the Lower Keg River can stratigraphically trap gas.

Table 3 lists the discoveries that have been made in this play. Thirteen reservoirs are noted, with a combined OGIP of 86.3 BCF. It is also evident that the play may be inactive, with the last discovery occurring in 1988. However, given the nature of the play (i.e. stratigraphic), it is likely that this is a difficult play to pursue, especially with the technology of the early 1980’s. It is possible that modern 3D seismic amplitude extraction techniques would aid in the search for additional targets in this play, so it would be premature to not consider further upside in this Lower Keg River play.

The high estimate and low estimate pool size by rank graphs are presented as Plots 16 and 17, respectively. In the high estimate, the shallower slope suggested by the smaller reservoirs is honoured, resulting in an estimate of 48 additional discoveries with a combined OGIP of 77 BCF. In the low estimate, the slope dictated by the third through six ranked pools is held fairly constant. This plot would suggest that there are 19 discoveries remaining, with a total OGIP of 27 BCF. GLJ has used the low estimate as the best estimate.

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Pine Point – Yoyo Play

As shown diagrammatically on Map 4, the margin region of the Upper Keg River can contain dolomitized reefs that form distinct traps for gas entrapment. The dolomite is likely hydrothermal in origin, created by the vertical movement of hot, magnesium-rich ground water through limestone. This results in the formation of dolomite from the lower to the upper levels of the Keg River. This dolomite also provides the improved reservoir quality necessary for the entrapment and subsequent commercial production of natural gas.

The first discovery in this play occurred in 1961 (Table 3). Discoveries are continuing to this day, with the latest reserves assignment published for a well drilled in March of 2000. GLJ notes that there are six production entities reported for wells drilled in the last two years, again suggesting that there remains reasonably good upside in this play.

The high estimate pool size by rank plot, presented as Plot 18, suggests that a significant number of large reservoirs are still left to be found, which is not unreasonable considering the drilling history. Table 3 shows that some of the largest pools in the play have been discovered fairly recently. Examples include the Klua Pine Point L (47 BCF, discovered in December, 1999), and the Sierra Pine Point G (36 BCF, discovered in January of 2000). It is possible that the use of 3D seismic could be aiding the exploration of this play. The high estimate suggests that there may be 49 undiscovered pools with a combined OGIP of 830 BCF. In the low estimate pool size by rank plot, far fewer large reservoirs are recognized. The slope suggested by the medium to small size discoveries is held fairly constant, but is not as smooth as in the high estimate (Plot 19). This interpretation would suggest that there are 32 reservoirs left to discover, with a combined OGIP of 238 BCF.

GLJ interprets that the recent successes support a best estimate that is 50 percent of the high estimate, resulting in an undiscovered best estimate of 534 BCF.

Summary of Undiscovered OGIP and Comparison to NEB Estimates

The low, high and best estimates for the undiscovered OGIP are summarized on Table 5. The combination of these values suggests that the undiscovered OGIP for the main producing horizons in the study area lays between a low of about 1762 BCF and a high of 4764 BCF, with a current best estimate of 2999 BCF.

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As a comparison of other sources of resource estimates, GLJ reviewed a Natural Gas Resource Assessment conducted by the NEB (reference 4). Using data that was supplied by the British Columbia Ministry of Energy, Mines and Petroleum Resources (BCEMPR) that included reserves to the end of 1992, the NEB employed a probabilistic model to estimate the undiscovered OGIP for the Plains/Peace River Arch area of 23,028 BCF (Table 2, pg 3). In the nine years since that time, there has been a total of 4,228 BCF discovered in these two regions, leaving a remaining undiscovered OGIP of 18,800 BCF. Of the 4,228 BCF discovered since the end of 1992, 704 BCF or about 16.6 percent has been found in the main plays discussed above, within the area of interest. A simple calculation suggests that about 3,221 BCF (equal to 0.166 * 18,800) should be remaining in these plays. This figure is approximately 7 percent higher than the GLJ best estimate at this time.

The NEB updated the 1994 study using data to the end of 1997. This report (reference 5) estimates the remaining undiscovered marketable gas volume at 14,154 BCF for the Plains and Peace River Arch regions (Table 3). Using the ratio of OGIP to Marketable Gas for the Plains/Peace River Arch region from the 1994 report, the above figure suggests an undiscovered OGIP of about 21,968 BCF as of the end of 1997. In the four years since that time, an OGIP of 1,878 BCF has been discovered, leaving approximately 20,090 BCF remaining. Of the 1,878 BCF discovered since the end of 1997, 269.3 BCF has been found in the area of interest in the major plays discussed previously, or about 14.3 percent of the total. Following the same arithmetic as for the earlier report, one can calculate a remaining undiscovered OGIP of 2,873 BCF. This is reasonably close to the figure of 3,221 BCF calculated using the earlier report, and is 4 percent lower than the best estimate of GLJ at this time.

These two calculations suggest that the GLJ best estimate is consistent with NEB estimates that have been made using a different approach.

Gilbert Laustsen Jung Associates Ltd. Page: 27 of 71

GAS SUPPLY FORECASTS

Table 6 summarizes total natural gas resources in the study area for each formation. In Table 6, “Recent Additions” refers to nonproducing reserves attributed to recent gas well completions in pools not identified in the BCOGC reserves database.

Forecasts of production from developed reserves were forecast to follow established decline trends where applicable. Producing entities not exhibiting declining production were forecast to maintain existing trends and then follow a terminal decline rate similar to other entities in the same formation. Nonproducing entities were forecast to initially produce at rates typical of other entities in the same horizon and to follow similar terminal decline rates. Marketable gas production was derived on a pool basis using gas shrinkage information in the BCOGC database.

Undiscovered resources were forecast to be identified and brought on stream giving consideration to historical discovery rates in each horizon. Plot 20 provides a history of exploration and gas well completions in the study area. It is noted that the area has in the past five years experienced increasing drilling activity. It is considered reasonable that finding rates will remain roughly consistent with historical statistics. Generally, it was forecast that between 50 percent and 75 percent of the undiscovered resources in each formation would be identified by drilling in the next 20 years.

Total area production forecasts are provided in Tables 7 through 9 and Plots 20 and 21.

Gilbert Laustsen Jung Associates Ltd. Page: 28 of 71 MAPS

TABLE OF CONTENTS

Page

Map 1 Location Map - Reserve Study Area 29 Map 2 Net Pay Map - Jean Marie Formation 30 Map 3 Play Areas Map - 31 Map 4 Play Areas Map - Pine Point Formation 32

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Gilbert Laustsen Jung Associates Ltd. Page: 33 of 71 PLOTS

TABLE OF CONTENTS

Page

Plot 1 Ekwan Area Historical Raw Gas Production 34 Plot 2 Example Reserves Determination - Thetlaandoa Debolt A - Gas Time 35 Semilog/Gas Cum Coord Plot Plot 3 Example Reserves Determination - Sierra Pine Point A - Gas Time 36 Semilog/Gas Cum Coord Plot Plot 4 Example Reserves Determination - Kotcho Lake Slave Point A - Gas Time 37 Semilog/Gas Cum Coord Plot Plot 5 Example Reserves Determination - Gote Sulphur Point A - Gas Time 38 Semilog/Gas Cum Coord Plot Plot 6 Jean Marie Production History and Forecast - Rate Time 39 Plot 7 Jean Marie Production History and Forecast - Rate Cum 40 Plot 8 Bluesky Play - High Case 41 Plot 9 Bluesky Play - Low Case 42 Plot 10 Debolt Play - High Case 43 Plot 11 Debolt Play - Low Case 44 Plot 12 Slave Point Formation - Adsett Play - High Case 45 Plot 13 Slave Point Formation - Adsett Play - Low Case 46 Plot 14 Slave Point Formation - Clarke Lake Play - High Case 47 Plot 15 Slave Point Formation - Clarke Lake Play - Low Case 48 Plot 16 Pine Point Formation - July Lake Play - High Case 49 Plot 17 Pine Point Formation - July Lake Play - Low Case 50 Plot 18 Pine Point Formation - Yoyo Play - High Case 51 Plot 19 Pine Point Formation - Yoyo Play - Low Case 52 Plot 20 Gas Supply Forecast by Classification 53 Plot 21 Gas Supply Forecast by Zone 54

Gilbert Laustsen Jung Associates Ltd. Historical Production Historical Production - Total Study Area Raw Gas

Property : Study Area 800 720 640 560 480 400 320 240 Daily Gas Calendar Day (MMcf/cd) 160 80 0 700 200 # Gas Wells WGR (bbl/MMcf) 0 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 00 01 02 03 0 Year

Cumulative Production Average Production Rates (Last 12 months ending 2002/12/31) Gas : 4658811.5 MMcf Gas : 681666.1 Mcf/d 589443.0 Mcf/cd WGR : 103.7 bbl/MMcf Oil : 7808.0 Mbbl Oil : 11009.6 bbl/d 8095.0 bbl/cd GOR : 72756.7 scf/stb Water : 102373.4 Mbbl Avg Wells : 585.4 WC : 88.3 % Plot 1 Page: 34 of 71

Historical Production - Total Study Area Raw Gas 1035834 / Mar 05, 2003 Gilbert Laustsen Jung Associates Ltd. Page: 35 of 71

Historical and Forecast Production Example Reserves Determination - Thetlaandoa Debolt A 100000 100000 Projections Illustrate Production Forecast

X G

A 10000 10000 Daily Gas (Mcf/d) 1000 1000 Daily Gas Calendar Day (Mcf/cd) 100 100 20 10 # Gas Wells WGR (bbl/MMcf) 0 0 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Year 80 80 2005 Projections Illustrate 72 72

Decline Analysis 2002 64 64 1999 56 56 1996 48 48 1993 40 40 Year 1990 32 32 Daily Gas (MMcf/d) 1987 24 24 Daily Gas Calendar Day (MMcf/cd) 1984 16 16 1981 8 8 1978

0 0 A G X 1975 20 10 # Gas Wells WGR (bbl/MMcf) 0 0 0 20000 40000 60000 80000 100000 120000 140000 160000 180000 200000 Cumulative Gas (MMcf)

Decline Analysis Summary @ 2003/01/01 Average Production Rates (Last 12 months ending 2002/12/31) Reserves ( MMcf ) Rates ( mcf/d ) Decline Gas : 45266.4 Mcf/d 39884.3 Mcf/cd WGR : 2.7 bbl/MMcf Reserves Oil : 0.0 bbl/d 0.0 bbl/cd GOR : 0.0 scf/stb Classification Ultimate Cum Prd Remain Initial Final Initial Expont Avg Wells : 7.5 WC : 100.0 % Pv Prd A 130000 20678 109322 45500 750 13.9% 0.00 Cumulative Production Pv + Pb Prd G 140000 20678 119322 45500 750 12.8% 0.00 Oil : 0.0 Mbbl Gas : 20678.0 MMcf Water : 62.0 Mbbl Tot Pv + Pb + Poss X 170000 20678 149322 45500 750 11.3% 0.10

Example Reserves Determination - Thetlaandoa Debolt A Plot 2 1035834 / Mar 13, 2003 Gilbert Laustsen Jung Associates Ltd. Page: 36 of 71

Historical and Forecast Production Example Reserves Determination - Sierra Pine Point A 1000000 1000000 Projections Illustrate Production Forecast 100000 100000

GX

A Daily Gas (Mcf/d) 10000 10000 Daily Gas Calendar Day (Mcf/cd) 1000 1000 20 80 # Gas Wells WGR (bbl/MMcf) 0 0 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Year 250 250 2008 Projections Illustrate 225 225

Decline Analysis 2004 200 200 2000 175 175 1996 150 150 1992 125 125 Year 1988 100 100 Daily Gas (MMcf/d) 1984 75 75 Daily Gas Calendar Day (MMcf/cd) 1980 50 50 1976 25 25 1972 0 0

AGX 1968 20 80 # Gas Wells WGR (bbl/MMcf) 0 0 0 100000 200000 300000 400000 500000 600000 700000 800000 900000 1000000 1100000 1200000 1300000 1400000 1500000 Cumulative Gas (MMcf)

Decline Analysis Summary @ 2003/01/01 Average Production Rates (Last 12 months ending 2002/12/31) Reserves ( MMcf ) Rates ( mcf/d ) Decline Gas : 77956.3 Mcf/d 72119.3 Mcf/cd WGR : 62.3 bbl/MMcf Reserves Oil : 0.0 bbl/d 0.0 bbl/cd GOR : 0.0 scf/stb Classification Ultimate Cum Prd Remain Initial Final Initial Expont Avg Wells : 10.5 WC : 100.0 % Pv Prd A 1260000 980227 279773 77000 1000 10.3% 0.10 Cumulative Production Pv + Pb Prd G 1270000 980227 289773 78000 1000 10.1% 0.10 Oil : 0.0 Mbbl Gas : 980227.4 MMcf Water : 11453.3 Mbbl Tot Pv + Pb + Poss X 1280000 980227 299773 79000 1000 9.9% 0.10

Example Reserves Determination - Sierra Pine Point A Plot 3 1035834 / Mar 13, 2003 Gilbert Laustsen Jung Associates Ltd. Page: 37 of 71

Historical and Forecast Production Example Reserves Determination - Kotcho Lake Slave Point A 100000 100000 Projections Illustrate Production Forecast

10000 10000 X G

A Daily Gas (Mcf/d) 1000 1000 Daily Gas Calendar Day (Mcf/cd) 100 100 5 200 # Gas Wells WGR (bbl/MMcf) 0 0 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Year 25.0 25.0 2008 Projections Illustrate 22.5 22.5 Production Forecast 2004 20.0 20.0 2000 17.5 17.5 1996 15.0 15.0 1992 12.5 12.5 Year 1988 10.0 10.0 Daily Gas (MMcf/d) 1984 7.5 7.5 Daily Gas Calendar Day (MMcf/cd) 1980 5.0 5.0 1976 2.5 2.5 1972

A G X 0.0 0.0 1968 10 2000 # Gas Wells WGR (bbl/MMcf) 0 0 0 10000 20000 30000 40000 50000 60000 70000 80000 90000 100000 110000 120000 130000 140000 150000 Cumulative Gas (MMcf)

Reserves Summary @ 2003/01/01 Average Production Rates (Last 12 months ending 2002/12/31) Reserves ( MMcf ) Gas : 17181.8 Mcf/d 16003.7 Mcf/cd WGR : 6.9 bbl/MMcf Reserves Oil : 0.0 bbl/d 0.0 bbl/cd GOR : 0.0 scf/stb Classification Ultimate Cum Prd Remain Reserves Method(s) Avg Wells : 2.4 WC : 100.0 % Pv Prd A 91000 54704 36296 Decline Cumulative Production Pv + Pb Prd G 97000 54704 42296 Decline Oil : 0.0 Mbbl Gas : 54703.7 MMcf Water : 3917.8 Mbbl Tot Pv + Pb + Possible X 110000 54704 55296 Decline

Example Reserves Determination - Kotcho Lake Slave Point A Plot 4 1035834 / Mar 13, 2003 Gilbert Laustsen Jung Associates Ltd. Page: 38 of 71

Historical and Forecast Production Example Reserves Determination - Gote Sulphur Point A Regulatory Field : Gote Well Name : Enerplus et al Gote D- 037-D/094-P-12 Regulatory Pool : Sulphur Point A Operator : Westrock Energy Resources Ii Corp. 100000 100000 Projections Illustrate Production Forecast 10000 10000

X

Daily Gas (Mcf/d) G

1000 1000 A Daily Gas Calendar Day (Mcf/cd) 100 100 10 WGR (bbl/MMcf) 0 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Year 20 20 2005 Projections Illustrate 18 18

Production Forecast 2002 16 16 1999 14 14 1996 12 12 1993 10 10 Year 1990 8 8 Daily Gas (MMcf/d) 1987 6 6 Daily Gas Calendar Day (MMcf/cd) 1984 4 4 1981 2 2 1978 0 0

A G X 1975 10 WGR (bbl/MMcf) 0 0 10000 20000 30000 40000 50000 60000 70000 80000 Cumulative Gas (MMcf)

Reserves Summary @ 2003/01/01 Average Production Rates (Last 12 months ending 2002/12/31) Reserves ( MMcf ) Gas : 3884.0 Mcf/d 2974.3 Mcf/cd WGR : 2.2 bbl/MMcf Reserves Oil : 0.0 bbl/d 0.0 bbl/cd GOR : 0.0 scf/stb Classification Ultimate Cum Prd Remain Reserves Method(s) On Prod : 279.0 days WC : 100.0 % Pv Prd A 58000 48087 9913 Dec, Mat Bal Cumulative Production Pv + Pb Prd G 60000 48087 11913 Dec, Mat Bal Oil : 0.0 Mbbl Gas : 48184.3 MMcf Water : 141.1 Mbbl Tot Pv + Pb + Possible X 63000 48087 14913 Dec, Mat Bal

Example Reserves Determination - Gote Sulphur Point A Plot 5 1035834 / Mar 13, 2003 Gilbert Laustsen Jung Associates Ltd. Historical and Forecast Production Producing

Property : Jean Marie

1000000 1000000 Projections Illustrate Production Forecast

GX 100000 100000 A Daily Gas (Mcf/d) 10000 10000 Daily Gas Calendar Day (Mcf/cd) 1000 1000 10 500 # Gas Wells WGR (bbl/MMcf) 0 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 0

Plot 6 Year

Total Reserves Summary @ 2003/01/01 Average Production Rates (Last 12 months ending 2002/12/31) Reserves ( MMcf ) Gas : 307795.5 Mcf/d 262623.0 Mcf/cd WGR : 3.0 bbl/MMcf Reserves Oil : 0.0 bbl/d 0.0 bbl/cd GOR : 0.0 scf/stb Classification Ultimate Cum Production Remaining Avg Wells : 391.5 WC : 100.0 % Pv Prd A(R) 1327020 663962 663058 Cumulative Production

Pv + Pb Prd G(R) 1415860 663962 751898 Page: 39 of 71 Oil : 10.7 Mbbl Gas : 663962.1 MMcf Water : 1092.2 Mbbl Tot Pv + Pb + Possible X(R) 1510800 663962 846838

Producing 1035834 / Mar 05, 2003 Gilbert Laustsen Jung Associates Ltd. Historical and Forecast Production Producing

Property : Jean Marie 400 400 2007 Projections Illustrate 360 360

Production Forecast 2004 320 320 2001 280 280 1998 240 240 1995 200 200 Year 1992 160 160 1989 Daily Gas (MMcf/d) 120 120 1986 Daily Gas Calendar Day (MMcf/cd) 80 80 1983 40 40 1980 A G X 0 0 1977 10 500 # Gas Wells WGR (bbl/MMcf) 0 0 0 200000 400000 600000 800000 1000000 1200000 1400000 1600000 1800000 2000000 Plot 7 Cumulative Gas (MMcf)

Total Reserves Summary @ 2003/01/01 Average Production Rates (Last 12 months ending 2002/12/31) Reserves ( MMcf ) Gas : 307795.5 Mcf/d 262623.0 Mcf/cd WGR : 3.0 bbl/MMcf Reserves Oil : 0.0 bbl/d 0.0 bbl/cd GOR : 0.0 scf/stb Classification Ultimate Cum Production Remaining Avg Wells : 391.5 WC : 100.0 % Pv Prd A(R) 1327020 663962 663058 Cumulative Production

Pv + Pb Prd G(R) 1415860 663962 751898 Page: 40 of 71 Oil : 10.7 Mbbl Gas : 663962.1 MMcf Water : 1092.2 Mbbl Tot Pv + Pb + Possible X(R) 1510800 663962 846838

Producing 1035834 / Mar 05, 2003 Gilbert Laustsen Jung Associates Ltd. Bluesky Play High Case

100,000 Discovered = 53 BCF in 13 pools Undiscovered = 67 BCF in 46 pools

Order of Discovery

1 13 10,000

9 4 7 3 6 12 5

10 11 OGIP (MMCF) 2 1,000 8

100 0 10 20 30 40 50 60 Pool Rank

Discovered Undiscovered Page: 41 of 71 Plot 8

Gilbert Laustsen Jung Associates Ltd. Bluesky Play Low Case

100,000 Discovered = 52 BCF in 12 pools Undiscovered = 30 BCF in 28 pools

Order of Discovery

1 13 10,000

9 4 7 3 6 12 5

10 11 OGIP (MMCF) 2 1,000 8

100 0 10 20 30 40 Pool Rank

Discovered Undiscovered Page: 42 of 71 Plot 9

Gilbert Laustsen Jung Associates Ltd. Debolt Play High Case

100,000 Discovered = 80 BCF in 19 pools Undiscovered = 106 BCF in 81 pools

2 4 3 Order of Discovery 10,000

15 18 14 5 171 6 16 713 8 11 1012 9 OGIP (MMCF) 1,000 19

100 0 20 40 60 80 100 Pool Rank

Discovered Undiscovered Page: 43 of 71 Plot 10

Gilbert Laustsen Jung Associates Ltd. Debolt Play Low Case

100,000 Discovered = 80 BCF in 19 pools Undiscovered = 60 BCF in 47 pools Order of Discovery

2 4 3 10,000

15 18 14 5 171 616 713 8 11 1012 9 OGIP (MMCF) 1,000 19

100 0 20 40 60 80 Pool Rank

Discovered Undiscovered Page: 44 of 71 Plot 11

Gilbert Laustsen Jung Associates Ltd. Slave Point Formation Adsett Play Type - High Case

1,000,000 Discovered = 672 BCF in 29 pools Undiscovered = 352 BCF 3 in 65 pools Order of Discovery

100,000 26

29 8 12 22 17 11 4 28 7 2715 25 1 2 9 10,000 6 19 1816 14 20 23 21 13

OGIP (MMCF) 10 24 5

1,000

100 0 10 20 30 40 50 60 70 80 90 Pool Rank

Discovered Undiscovered Page: 45 of 71 Plot 12

Gilbert Laustsen Jung Associates Ltd. Slave Point Formation Adsett Play Type - Low Case

1,000,000 Discovered = 672 BCF in 29 pools Undiscovered = 159 BCF 3 in 41 pools Order of Discovery

100,000 26

29 8 12 22 17 11 4 28 7 27 15 25 1 2 9 10,000 6 19 18 16 14 20 23 21 13

OGIP (MMCF) 10 24 5

1,000

100 0 10 20 30 40 50 60 70 Pool Rank

Discovered Undiscovered Page: 46 of 71 Plot 13

Gilbert Laustsen Jung Associates Ltd. Slave Point Formation Clarke Lake Play Type - High Case

1,000,000 Discovered = 1198 BCF in 42 pools Undiscovered = 354 BCF in 65 pools

100,000

10,000 OGIP (MMCF)

1,000

100 0 10 20 30 40 50 60 70 80 90 100 110 120 Pool Rank

Discovered Undiscovered Page: 47 of 71 Plot 14

Gilbert Laustsen Jung Associates Ltd. Slave Point Formation Clarke Lake Play Type - Low Case

1,000,000 Discovered = 1198 BCF in 42 pools Undiscovered = 130 BCF in 42 pools

100,000

10,000 OGIP (MMCF)

1,000

100 0 10 20 30 40 50 60 70 80 90 Pool Rank

Discovered Undiscovered Page: 48 of 71 Plot 15

Gilbert Laustsen Jung Associates Ltd. Pine Point Formation July Lake Play Type - High Case

100,000 Discovered = 86 BCF in 13 pools Undiscovered = 77 BCF Order of Discovery in 48 pools

4

5

10 10,000 1 8 7 11

9 3 2

13

12 6 OGIP (MMCF) 1,000

100 0 10 20 30 40 50 60 70 80 Pool Rank

Discovered Undiscovered Page: 49 of 71 Plot 16

Gilbert Laustsen Jung Associates Ltd. Pine Point Formation July Lake Play Type - Low Case

100,000 Discovered = 86 BCF in 13 pools Undiscovered = 27 BCF in 19 pools

4 Order of Discovery

5 10 10,000 1 8 7 11 9 3 2

13 12 6 OGIP (MMCF) 1,000

100 0 5 10 15 20 25 30 35 Pool Rank

Discovered Undiscovered Page: 50 of 71 Plot 17

Gilbert Laustsen Jung Associates Ltd. Pine Point Formation Yoyo Play Type - High Case

10,000,000 Discovered = 5,056 BCF in 36 Order of Discovery pools 2 Undiscovered = 830 BCF 3 in 49 pools

1,000,000 4 11

100,000 1528 10 3322 16 7 34 2724 3523 6 21 9 36 8 12

14 1 10,000OGIP (MMCF) 3020 5 1817 26 1325 31 32

29

1,000 19

100 0 10 20 30 40 50 60 70 80 90 Pool Rank

Discovered Undiscovered Page: 51 of 71 Plot 18

Gilbert Laustsen Jung Associates Ltd. Pine Point Formation Yoyo Play Type - Low Case

10,000,000 Discovered = 5,056 BCF in 36 pools Order of Discovery Undiscovered = 238 BCF 2 in 32 pools 3 1,000,000 4 11

100,000 15 28 10 33 22 16 7 34 27 24 35 23 6 21 9 36 8 12 14 10,000 1 30 20 5 OGIP (MMCF) 18 17 26 13 25 31 32 29

1,000 19

100 0 10 20 30 40 50 60 70 Pool Rank

Discovered Undiscovered Page: 52 of 71 Plot 19

Gilbert Laustsen Jung Associates Ltd. Page: 53 of 71

Gas Supply Forecast by Reserve and Resource Classification

Gas Supply Forecast - Low Estimate Case

600

Undiscovered Contingent Resources 500 NonProd+Undev Reserves Producing Reserves

400

300

Sales Rate MMcfd 200

100

-

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Year

Gas Supply Forecast - Best Estimate Case

900

800 Undiscovered Contingent Resources NonProd+Undev Reserves Producing Reserves 700

600

500

400 Sales Rate MMcfd 300

200

100

-

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Year

Gas Supply Forecast - High Estimate Case

1,200

Undiscovered Contingent Resources 1,000 NonProd+Undev Reserves Producing Reserves

800

600 Sales Rate MMcfd 400

200

-

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Year Plot 20

Gilbert Laustsen Jung Associates Ltd. Page: 54 of 71

Gas Supply Forecast by Zone

Gas Supply Forecast - Low Estimate Case

600

Jean Marie Miss-Debolt Pine Point Slave Point 500 Other Zones

400

300 Sales Rate MMcfd 200

100

0

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Year

Gas Supply Forecast - Best Estimate Case

900

800 Jean Marie Miss-Debolt Pine Point Slave Point Other Zones 700

600

500

400 Sales Rate MMcfd 300

200

100

-

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Year

Gas Supply Forecast - Best Estimate Case

1,200

Jean Marie Miss-Debolt Pine Point Slave Point 1,000 Other Zones

800

600 Sales Rate MMcfd 400

200

-

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Year

Plot 21

Gilbert Laustsen Jung Associates Ltd. Page: 55 of 71 TABLES

TABLE OF CONTENTS

Page

Table 1 Ekwan Study Area - Total Gas Resources 56 Table 2 Ekwan Study Area - Total Marketable Gas Supply Forecast 57 Table 3 Ekwan Study Area - Summary of BCOGC Individual Pool Reserves Estimates 58 Table 4 Ekwan Study Area - Summary of Jean Marie Reserves 64 Table 5 Ekwan Study Area - Summary of Undiscovered Resources 66 Table 6 Ekwan Study Area - Total Gas Resources 67 Table 7 Ekwan Study Area - Gas Supply Forecast (Low Case) 68 Table 8 Ekwan Study Area - Gas Supply Forecast (Best Estimate Case) 69 Table 9 Ekwan Study Area - Gas Supply Forecast (Maximum Case) 70

Gilbert Laustsen Jung Associates Ltd. Page: 56 of 71

Table 1 Ekwan Study Area Summary of Total Gas Resources (Bcf)

Low Best High Estimate Estimate Estimate Initial Reserves - Producing 6271 6475 6669 Initial Reserves - Nonprod/Undev 473 940 1143 Contingent Resources 249 427 661 Undiscovered Resources 591 1170 1871 Cumulative Production 4657 4657 4657 Remaining Raw Reserves 2927 4355 5686 Remaining Marketable Reserves 2527 3800 4989

Best Estimate Initial Resources Remaining Producing Reserves

Nonprod/Undev Reserves Cumulative Production

Contingent Resources

Undiscovered Resources

Best Estimate - Remaining Raw Resources

Undiscovered Resources

Producing Reserves

Contingent Resources

Nonprod/Undev Reserves

Gilbert Laustsen Jung Associates Ltd. Table 2 Ekwan Supply Study Ekwan Area Total Gas Supply Forecast (MMcfd sales)

History Forecast

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Low Estimate 406 378 391 407 422 481 502 532 541 550 555 548 502 437 383 337 297 263 234 208 185 165 147 131 116 Best Estimate 406 378 391 407 422 481 502 648 694 732 765 791 808 758 665 590 526 462 412 322 262 229 199 178 159 High Estimate 406 378 391 407 422 481 502 692 792 874 940 998 1042 987 866 764 682 614 548 476 379 334 292 253 227

Ekwan Area Gas Supply Forecast

1,200

Low Estimate 1,000 Best Estimate High Estimate

800

600

400 Marketable Gas Rate MMcfd

200

-

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Year Page: 57 of 71

Gilbert Laustsen Jung Associates Ltd. Page: 58 of 71

Table 3 Ekwan Study Area

Summary of British Columbia Oil and Gas Commission Reserves and Production

Prod. Stat's as of Nov. 30, 2002 BCOGC Reserves Estimates as of December 31, 2001 Prod Cumul. Last 3 mo. Initial Res. Cumul Rem Res. Rem Mrkbl Disc Well Well Gas Gas Rate OGIP Rec Raw Gas Prod Raw Gas Surf Reserves Year PT* Field Pool Name Count Count MMcf Mcfd (MMcf) Fac (MMcf) (MMcf) (MMcf) Loss (MMcf) Jean Marie GUNNELL CREEK JEAN MARIE A 81 63 44,994 36,908 320,578 90% 287,851 32,013 255,837 12% 225,331 1979 HELMET NORTH JEAN MARIE A 76 62 260,764 42,499 393,664 90% 354,298 245,805 108,492 4% 103,643 1990 SIERRA JEAN MARIE A 26 19 9,722 7,675 104,839 90% 94,355 6,964 87,391 16% 73,595 1999 EKWAN JEAN MARIE A 37 23 6,207 4,980 107,632 80% 86,105 4,504 81,602 12% 71,769 1995 PEGGO-PESH JEAN MARIE A 117 84 141,270 41,010 217,726 90% 195,953 128,802 67,151 5% 63,935 1984 PEGGO-PESH JEAN MARIE B 16 11 5,400 5,331 37,718 90% 33,947 3,254 30,692 5% 29,262 1997 MIDWINTER JEAN MARIE C 27 23 42,331 8,705 75,506 80% 60,405 38,885 21,520 4% 20,569 1980 HELMET JEAN MARIE F 69 57 54,820 24,929 80,137 80% 64,109 45,474 18,636 9% 16,964 1981 MIDWINTER JEAN MARIE A 19 16 31,357 7,592 55,325 80% 44,260 28,665 15,595 4% 14,910 1980 HELMET JEAN MARIE A 28 19 14,878 5,093 31,816 80% 25,453 11,815 13,638 13% 11,925 1976 SAHTANEH JEAN MARIE A 7 6 4,678 3,408 20,039 80% 16,031 3,073 12,959 15% 10,963 1979 TSEA JEAN MARIE A 2 1 1,150 410 3,393 90% 3,054 1,019 2,035 15% 1,735 1996 CABIN JEAN MARIE A 3 1 577 1,707 4,320 25% 1,080 - 1,080 24% 824 1977 MIDWINTER JEAN MARIE D 1 1 106 122 624 80% 499 60 439 4% 420 1980 GUNNELL CREEK JEAN MARIE E 5 3 727 645 653 80% 523 85 438 13% 382 2001 HELMET JEAN MARIE J 1 1 1,368 273 1,675 90% 1,508 1,257 251 12% 222 1996 OTHER AREAS JEAN MARIE C-094-B/094-P-07 1 1 880 195 1,124 90% 1,011 821 190 12% 168 1997 HELMET JEAN MARIE 22 16 10,284 10,134 - 1998 HELMET NORTH JEAN MARIE 11 9 6,900 9,647 - 1995 GUNNELL CREEK JEAN MARIE 8 7 884 6,480 - 2002 MIDWINTER JEAN MARIE 8 8 2,923 4,519 - 2001 DESAN JEAN MARIE 1 1 1,003 3,022 - 2002 SIERRA JEAN MARIE 4 3 743 2,753 - 2001 OTHER AREAS JEAN MARIE C-051-K/094-P-02 1 1 655 2,284 - 2002 SAHTANEH JEAN MARIE 3 1 197 2,162 - 2002 OTHER AREAS JEAN MARIE A-072-K/094-P-02 1 1 190 2,083 - 2002 OTHER AREAS JEAN MARIE A-021-L/094-I-12 1 1 180 1,981 - 2002 OTHER AREAS JEAN MARIE B-040-K/094-I-12 1 1 174 1,914 - 2002 PEGGO-PESH JEAN MARIE 3 2 546 1,846 - 2001 OTHER AREAS JEAN MARIE B-036-K/094-P-02 1 1 423 1,505 - 2002 GUNNELL CREEK JEAN MARIE D 3 3 527 1,178 - 2001 TSEA JEAN MARIE 1 1 354 1,068 - 2002 OTHER AREAS JEAN MARIE A-043-G/094-I-08 2 1 164 761 - 2002 OTHER AREAS JEAN MARIE D-052-G/094-I-08 1 1 150 755 - 2001 OTHER AREAS JEAN MARIE A-081-F/094-P-02 1 1 162 576 - 2002 SAHTANEH JEAN MARIE C 3 2 530 555 - 2001 OTHER AREAS JEAN MARIE C-003-C/094-P-05 1 1 240 541 - 2001 OTHER AREAS JEAN MARIE B-075-K/094-P-02 1 1 43 468 - 2002 OTHER AREAS JEAN MARIE D-032-H/094-P-14 1 1 172 444 - 2002 OTHER AREAS JEAN MARIE A-098-B/094-P-01 1 1 217 436 - 1998 OTHER AREAS JEAN MARIE C-035-F/094-P-02 1 1 139 432 - 2001 OTHER AREAS JEAN MARIE C-008-L/094-P-02 1 1 266 408 - 2001 OTHER AREAS JEAN MARIE C-095-K/094-P-02 1 1 36 394 - 2002 KOTCHO LAKE JEAN MARIE 3 1 345 373 - 1979 OTHER AREAS JEAN MARIE B-062-F/094-P-15 1 1 499 358 - 2000 THETLAANDOA SOUTH JEAN MARIE A 2 1 341 348 - 2001 OTHER AREAS JEAN MARIE A-079-G/094-I-14 1 1 78 305 - 2000 GUNNELL CREEK JEAN MARIE F 2 1 119 301 - 2001 KOTCHO LAKE EAST JEAN MARIE 1 1 240 287 - 2001 OTHER AREAS JEAN MARIE A B-083-C/094-I-13 1 1 1,909 281 - 1960 OTHER AREAS JEAN MARIE A-093-E/094-P-02 1 1 170 272 - 2001 OTHER AREAS JEAN MARIE D-018-L/094-I-05 1 1 74 257 - 2001 KYKLO JEAN MARIE 2 1 217 254 - 2000 OTHER AREAS JEAN MARIE C-008-J/094-I-14 1 1 84 232 - 2002 HAY RIVER JEAN MARIE 2 1 49 226 - 2002 OTHER AREAS JEAN MARIE D-002-E/094-P-02 1 1 81 216 - 2001 TOOGA JEAN MARIE 1 1 65 211 - 2001 OTHER AREAS JEAN MARIE A-007-L/094-P-02 2 1 65 205 - 2002 SEXTET JEAN MARIE 3 2 262 199 - 1991 OTHER AREAS JEAN MARIE D-047-I/094-I-08 1 1 38 170 - 2002 YOYO JEAN MARIE 2 2 66 151 - 1974 THETLAANDOA SOUTH JEAN MARIE B 1 1 204 132 - 2001 OTHER AREAS JEAN MARIE A-092-H/094-P-03 1 1 83 131 - 2001 SAHTANEH JEAN MARIE B 2 1 222 112 - 2001 SAHTANEH JEAN MARIE D 2 1 79 102 - 2001 OTHER AREAS JEAN MARIE C-015-J/094-I-06 1 1 241 29 - 1999 Gilbert Laustsen Jung Associates Ltd. Page: 59 of 71

Table 3 Ekwan Study Area

Summary of British Columbia Oil and Gas Commission Reserves and Production

Prod. Stat's as of Nov. 30, 2002 BCOGC Reserves Estimates as of December 31, 2001 Prod Cumul. Last 3 mo. Initial Res. Cumul Rem Res. Rem Mrkbl Disc Well Well Gas Gas Rate OGIP Rec Raw Gas Prod Raw Gas Surf Reserves Year PT* Field Pool Name Count Count MMcf Mcfd (MMcf) Fac (MMcf) (MMcf) (MMcf) Loss (MMcf) OTHER AREAS JEAN MARIE D-065-K/094-P-05 1 1 33 29 - 2001 EKWAN JEAN MARIE B 1 1 6 11 - 2000 GUNNELL CREEK JEAN MARIE G 1 0 - - - 2001 OTHER AREAS JEAN MARIE A-001-K/094-P-06 1 0 - - - 2001 OTHER AREAS JEAN MARIE A-040-K/094-I-05 1 0 - - - 2001 OTHER AREAS JEAN MARIE A-046-K/094-P-02 1 0 50 - - 2002 OTHER AREAS JEAN MARIE A-067-H/094-P-03 1 0 - - - 2001 OTHER AREAS JEAN MARIE A-069-H/094-I-08 1 0 - - - 2002 OTHER AREAS JEAN MARIE A-076-F/094-P-11 1 0 - - - 2000 OTHER AREAS JEAN MARIE A-087-B/094-P-04 1 0 - - - 2002 OTHER AREAS JEAN MARIE A-091-D/094-I-09 1 0 - - - 2002 OTHER AREAS JEAN MARIE B-005-C/094-P-07 1 0 - - - 2002 OTHER AREAS JEAN MARIE B-087-K/094-I-12 1 0 - - - 2002 OTHER AREAS JEAN MARIE C-010-F/094-I-05 1 0 - - - 2001 OTHER AREAS JEAN MARIE C-058-H/094-I-08 1 0 - - - 2002 OTHER AREAS JEAN MARIE C-078-G/094-I-14 1 0 142 - - 2000 OTHER AREAS JEAN MARIE D-008-G/094-P-04 1 0 - - - 2002 OTHER AREAS JEAN MARIE D-016-I/094-P-01 1 0 - - - 2001 OTHER AREAS JEAN MARIE D-027-B/094-P-02 1 0 - - - 2000 OTHER AREAS JEAN MARIE D-043-E/094-I-09 1 0 - - - 2002 OTHER AREAS JEAN MARIE D-071-F/094-P-02 1 0 - - - 2002 OTHER AREAS JEAN MARIE D-075-K/094-P-02 1 0 - - - 2002 OTHER AREAS JEAN MARIE D-078-K/094-P-11 1 0 - - - 2002 OTHER AREAS JEAN MARIE D-091-D/094-I-09 2 0 - - - 2002 PETITOT RIVER JEAN MARIE 1 0 - - - 2002 DESAN JEAN MARIE A 1 0 - - - 1997 EKWAN JEAN MARIE 1 0 - - - 1996 ELLEH JEAN MARIE A 1 0 - - - 1981 HOSSITL JEAN MARIE A 1 0 1 - - 1981 OTHER AREAS JEAN MARIE A-058-E/094-I-03 1 0 1 - - 1970 OTHER AREAS JEAN MARIE B-009-F/094-P-11 1 0 - - - 1999 OTHER AREAS JEAN MARIE B-062-D/094-P-14 1 0 1 - - 1981 OTHER AREAS JEAN MARIE B-081-I/094-I-14 1 0 - - - 1998 OTHER AREAS JEAN MARIE C-040-K/094-I-12 1 0 - - - 1985 Mississipian-Debolt BIVOUAC DEBOLT A 3 1 1,179 1,381 11,105 75% 8,329 531 7,798 13% 6,819 1972 BIVOUAC DEBOLT E 2 2 389 188 5,816 90% 5,234 279 4,955 13% 4,323 1997 KYKLO DEBOLT A 2 1 2,411 10 14,015 50% 7,007 2,333 4,674 16% 3,932 1972 THETLAANDOA DEBOLT A 11 8 17,137 36,463 11,271 90% 10,144 6,108 4,036 16% 3,381 1973 OTHER AREAS DEBOLT B-041-K/094-I-01 1 0 582 - 4,126 80% 3,301 395 2,906 13% 2,543 1994 BIVOUAC DEBOLT G 1 1 99 82 3,297 90% 2,967 38 2,930 13% 2,538 1998 BIVOUAC DEBOLT H 1 1 1,265 2,678 2,707 90% 2,437 326 2,111 13% 1,834 1998 OTHER AREAS DEBOLT A-023-I/094-I-04 1 0 2 - 1,419 90% 1,277 2 1,275 11% 1,138 1977 OTHER AREAS DEBOLT A-063-G/094-I-01 1 0 795 - 2,184 75% 1,638 707 931 13% 811 1985 OTHER AREAS DEBOLT B-024-B/094-P-11 1 0 2 - 1,411 50% 705 2 704 18% 577 1981 THETLAANDOA DEBOLT B 2 1 714 1,459 3,825 25% 956 338 618 16% 518 1973 HELMET DEBOLT B 5 3 4,430 1,596 5,019 90% 4,517 3,883 634 22% 493 1999 KLUA DEBOLT A 2 0 147 - 1,148 30% 344 338 6 15% 5 1977 OTHER AREAS DEBOLT C-053-D/094-P-06 1 1 370 1,437 3,256 75% 2,442 - 2,442 19% 1,987 1961 OTHER AREAS DEBOLT D-055-L/094-P-11 1 0 - - 2,228 75% 1,671 - 1,671 17% 1,384 1974 THETLAANDOA NORTH DEBOLT A 1 0 - - 2,907 25% 727 - 727 17% 606 1973 THETLAANDOA SOUTH DEBOLT A 2 0 - - 2,150 25% 538 - 538 16% 452 1974 KOTCHO LAKE DEBOLT A 1 0 - - 1,802 25% 450 - 450 18% 368 1979 OTHER AREAS MISSISSIPPIAN D-036-L/094-P-06 1 1 1,961 9,335 Thetlaandoa Debolt A - 2002 OTHER AREAS MISSISSIPPIAN B-062-L/094-P-06 1 1 1,193 5,681 Thetlaandoa Debolt A - 2002 OTHER AREAS MISSISSIPPIAN A-001-K/094-P-06 1 1 865 3,865 - 2001 THETLAANDOA NORTH MISSISSIPPIAN 1 1 619 1,703 - 2002 OTHER AREAS MISSISSIPPIAN A-004-B/094-P-11 1 1 261 838 - 2002 HELMET MISSISSIPPIAN 1 1 211 811 - 2002 THETLAANDOA MISSISSIPPIAN 2 1 154 618 - 2001 EKWAN DEBOLT 1 1 201 189 - 2000 GUNNELL CREEK DEBOLT 1 0 - - - 2001 OTHER AREAS DEBOLT A-048-J/094-I-01 1 0 - - - 2000 OTHER AREAS DEBOLT C-062-D/094-I-10 1 0 1 - - 2000 OTHER AREAS MISSISSIPPIAN A-035-D/094-P-11 1 0 0 - - 2002 OTHER AREAS MISSISSIPPIAN C-022-L/094-P-06 1 0 - - - 2001

Gilbert Laustsen Jung Associates Ltd. Page: 60 of 71

Table 3 Ekwan Study Area

Summary of British Columbia Oil and Gas Commission Reserves and Production

Prod. Stat's as of Nov. 30, 2002 BCOGC Reserves Estimates as of December 31, 2001 Prod Cumul. Last 3 mo. Initial Res. Cumul Rem Res. Rem Mrkbl Disc Well Well Gas Gas Rate OGIP Rec Raw Gas Prod Raw Gas Surf Reserves Year PT* Field Pool Name Count Count MMcf Mcfd (MMcf) Fac (MMcf) (MMcf) (MMcf) Loss (MMcf) OTHER AREAS MISSISSIPPIAN D-040-D/094-P-11 1 0 - - - 2002 OTHER AREAS MISSISSIPPIAN D-099-G/094-P-06 1 0 1 - - 2002 THETLAANDOA SOUTH MISSISSIPPIAN 1 0 - - - 2001 BIVOUAC DEBOLT 1 0 - - - 1998 BIVOUAC DEBOLT B 1 0 2 - - 1979 EKWAN DEBOLT A 1 0 - - - 1980 HELMET DEBOLT C 1 0 40 - - 1996 KOTCHO LAKE DEBOLT 2 0 - - - 1960 OTHER AREAS DEBOLT A-009-F/094-I-12 1 0 - - - 1991 OTHER AREAS DEBOLT B-088-H/094-I-06 1 0 - - - 1980 OTHER AREAS DEBOLT C-040-K/094-I-12 1 0 - - - 1985 OTHER AREAS DEBOLT C-075-D/094-I-08 1 0 - - - 1998 OTHER AREAS DEBOLT C-089-G/094-P-06 1 0 0 - - 1973 OTHER AREAS DEBOLT D-036-H/094-I-01 1 0 28 - - 1999 SAHTANEH DEBOLT 2 0 51 - - 1976 YOYO DEBOLT 1 0 - - - 1975

Other Zones

GOTE SULPHUR POINT A 1 1 48,087 2,966 83,765 70% 58,636 47,091 11,545 23% 8,854 1972 EKWAN KAKISA A 3 3 2,001 1,947 10,401 90% 9,361 1,337 8,024 11% 7,119 1979 EKWAN KAKISA D 3 3 1,283 1,116 9,143 90% 8,229 887 7,341 11% 6,546 1998 HAY RIVER BLUESKY A 2 1 920 1,720 5,286 55% 2,916 615 2,301 22% 1,785 1986 HELMET SHUNDA B 1 1 619 349 3,945 90% 3,551 1,507 2,043 18% 1,673 1980 EKWAN KAKISA E 2 1 209 158 2,004 90% 1,804 153 1,651 12% 1,459 2000 HAY RIVER BLUESKY B 1 0 567 1,145 3,303 50% 1,651 235 1,416 15% 1,205 1984 EKWAN BANFF A 1 1 264 211 1,701 80% 1,360 173 1,188 10% 1,067 1962 OTHER AREAS DETRITAL A-071-B/094-P-02 1 1 693 1,100 1,765 80% 1,412 306 1,105 16% 933 1978 HELMET BLUESKY A 1 1 1,005 249 2,447 80% 1,958 894 1,064 18% 870 1980 BIVOUAC BANFF A 2 1 369 209 1,491 80% 1,192 279 914 10% 820 1985 EKWAN KAKISA B 1 1 370 305 1,102 80% 881 273 608 11% 543 2000 EKWAN KAKISA C 1 1 387 479 1,025 80% 820 219 601 11% 535 1999 GUNNELL CREEK BLUESKY A 1 0 456 - 1,167 90% 1,051 456 594 12% 526 1996 OTHER AREAS MUSKWA-OTTER PARK-SLAVE POINT B-092-A/094-O-16 1 0 46 - 720 50% 360 46 314 23% 243 1992 SAHTANEH SULPHUR POINT A 1 0 550 - 2,410 35% 843 550 293 23% 225 1969 PEGGO-PESH BLUESKY B 1 0 1,977 - 2,662 80% 2,130 1,977 153 12% 134 1980 KOTCHO LAKE EAST BLUESKY A 1 0 148 - 4,425 4% 177 148 29 14% 25 1980 KOTCHO LAKE EAST BLUESKY B 2 0 2,466 - 12,320 20% 2,476 2,466 10 14% 9 1975 PEGGO-PESH BLUESKY A 1 1 474 50 1,646 27% 445 456 (12) 10% (11) 1989 HAY RIVER BLUESKY C 0 0 - - 2,572 80% 2,058 (42) 2,099 17% 1,738 1998 KOTCHO LAKE EAST BLUESKY D 1 0 - - 3,140 25% 785 - 785 18% 641 1976 SIERRA BLUESKY 3 2 4,099 3,395 - 1999 PEGGO-PESH BANFF A 1 1 393 671 - 2000 YOYO BLUESKY A 1 1 108 491 - 1975 THETLAANDOA DETRITAL A 1 1 151 365 - 2000 HELMET SHUNDA D 1 1 494 300 - 2000 OTHER AREAS DUNVEGAN C-082-K/094-P-02 1 1 21 136 - 2002 OTHER AREAS BLUESKY B-061-G/094-P-11 1 1 81 124 - 2001 SIERRA BANFF 4 1 67 69 - 1976 HELMET SHUNDA C 1 1 171 43 - 1999 OTHER AREAS BLUESKY A-038-J/094-P-11 1 1 12 0 - 2002 3 0 - - - 2000 EKWAN BANFF 1 0 - - - 2000 GUNNELL CREEK 1 0 - - - 2000 KOTCHO LAKE BANFF 1 0 - - - 2001 OTHER AREAS BANFF B-022-K/094-I-10 1 0 - - - 2001 OTHER AREAS BANFF B-029-H/094-P-02 1 0 4 - - 2001 OTHER AREAS BANFF B-081-L/094-I-10 1 0 - - - 2000 OTHER AREAS BANFF D-084-A/094-P-02 1 0 - - - 2000 OTHER AREAS BLUESKY A D-052-A/094-P-12 1 0 - - - 2001 OTHER AREAS BLUESKY A-048-J/094-I-01 1 0 - - - 2000 OTHER AREAS BLUESKY B-068-A/094-P-12 1 0 - - - 2002 OTHER AREAS BLUESKY C-010-K/094-P-11 1 0 - - - 2001 OTHER AREAS BLUESKY C-028-D/094-P-02 1 0 - - - 2001 OTHER AREAS BLUESKY D-016-J/094-P-11 1 0 - - - 2002 OTHER AREAS BLUESKY D-027-B/094-P-02 1 0 - - - 2000 OTHER AREAS DEVONIAN B-048-I/094-O-09 1 0 - - - 2001 Gilbert Laustsen Jung Associates Ltd. Page: 61 of 71

Table 3 Ekwan Study Area

Summary of British Columbia Oil and Gas Commission Reserves and Production

Prod. Stat's as of Nov. 30, 2002 BCOGC Reserves Estimates as of December 31, 2001 Prod Cumul. Last 3 mo. Initial Res. Cumul Rem Res. Rem Mrkbl Disc Well Well Gas Gas Rate OGIP Rec Raw Gas Prod Raw Gas Surf Reserves Year PT* Field Pool Name Count Count MMcf Mcfd (MMcf) Fac (MMcf) (MMcf) (MMcf) Loss (MMcf) OTHER AREAS DEVONIAN B-085-A/094-O-09 1 0 - - - 2001 OTHER AREAS DOIG D-073-D/094-H-14 1 0 - - - 2000 OTHER AREAS KOTCHO C-028-D/094-P-02 1 0 - - - 2001 OTHER AREAS SHUNDA D-052-A/094-P-12 1 0 - - - 2001 PEGGO-PESH BLUESKY 1 0 - - - 2000 THETLAANDOA NORTH 1 0 - - - 2001 BIVOUAC 2 0 - - - 1978 BIVOUAC DETRITAL 1 0 - - - 1998 DESAN BANFF A 1 0 0 - - 1984 DESAN BANFF B 1 0 0 - - 1985 DESAN DETRITAL 1 0 - - - 1984 DESAN PEKISKO 4 0 1 - - 1984 DESAN SHUNDA 1 0 - - - 1984 DESAN SHUNDA A 2 0 0 - - 1984 EKWAN 4 0 - - - 1982 HELMET 2 0 - - - 1997 HELMET DETRITAL A 2 0 - - - 1999 HELMET SHUNDA 1 0 - - - 1978 HELMET SHUNDA A 1 0 6 - - 1975 KOTCHO LAKE 3 0 - - - 1986 KOTCHO LAKE EAST 1 0 - - - 1998 KOTCHO LAKE EAST BLUESKY 1 0 - - - 1976 KYKLO BLUESKY 1 0 - - - 1980 MIDWINTER 2 0 - - - 1983 OTHER AREAS C-023-E/094-P-14 1 0 - - - 1994 OTHER AREAS C-038-F/094-I-05 1 0 - - - 1991 OTHER AREAS BANFF C-096-D/094-P-01 1 0 - - - 1998 OTHER AREAS BANFF D-055-H/094-I-16 1 0 0 - - 1985 OTHER AREAS BELLOY A-027-C/094-I-04 1 0 - - - 1999 OTHER AREAS BLUESKY-GETHING-MONTNEY B- 082-F/094-I-02 1 0 2 - - 1989 OTHER AREAS MONTNEY A-083-E/094-I-03 1 0 - - - 1995 OTHER AREAS MONTNEY B-044-E/094-I-02 1 0 - - - 1990 OTHER AREAS MONTNEY C-084-F/094-I-03 1 0 - - - 1995 PEGGO-PESH 6 0 - - - 1981 PESH 1 0 - - - 1987 SAHTANEH 2 0 - - - 1969 THETLAANDOA 2 0 - - - 1984 THETLAANDOA SHUNDA A 1 0 - - - 1984 TOOGA PEKISKO A 1 0 0 - - 1984

Pine Point

SIERRA PINE POINT A 19 12 977,824 69,098 1,394,903 90% 1,255,413 953,802 301,610 25% 224,730 1965 Y YOYO PINE POINT A 44 16 1,504,009 23,160 1,927,309 84% 1,618,939 1,494,135 124,805 27% 91,220 1970 Y SIERRA PINE POINT B 5 4 401,235 35,424 594,236 85% 505,100 383,505 121,596 28% 87,622 1967 Y SIERRA PINE POINT D 7 4 131,617 12,222 412,153 42% 171,044 128,403 42,640 26% 31,359 1978 Y KLUA PINE POINT L 1 1 2,739 537 47,058 80% 37,647 2,488 35,159 19% 28,496 1999 Y KLUA PINE POINT M 1 1 2,088 345 29,670 90% 26,703 1,884 24,819 34% 16,492 2000 Y SIERRA PINE POINT F 1 1 46,141 3,326 76,028 85% 64,623 44,709 19,914 28% 14,310 1991 Y MEL PINE POINT B 2 1 1,380 626 28,614 65% 18,599 1,078 17,521 26% 12,890 1994 Y KLUA PINE POINT N 1 1 182 91 15,256 60% 9,153 160 8,994 19% 7,261 2000 Y SIERRA PINE POINT G 1 0 21,860 - 36,311 80% 29,049 21,849 7,200 26% 5,301 1993 Y OTHER AREAS PINE POINT A-051-A/094-O-08 1 0 503 - 8,483 80% 6,786 503 6,283 22% 4,917 1961 Y KLUA PINE POINT D 2 2 23,579 5,605 46,601 60% 27,960 20,853 7,107 32% 4,838 1990 Y SIERRA PINE POINT E 1 1 64,477 3,403 80,652 85% 68,555 63,242 5,312 25% 3,969 1980 Y KLUA PINE POINT G 1 1 11,767 2,549 34,104 50% 17,052 10,895 6,157 39% 3,768 1991 Y PEGGO-PESH PINE POINT A 1 0 4 - 3,942 80% 3,154 4 3,149 27% 2,305 1968 J MEL PINE POINT A 1 1 613 249 13,093 25% 3,273 517 2,756 24% 2,099 1977 Y KLUA PINE POINT E 1 0 4,287 - 32,286 25% 8,072 4,287 3,784 45% 2,088 1990 Y GUNNELL CREEK PINE POINT A 1 0 1,788 - 4,908 90% 4,417 1,788 2,629 24% 2,003 1999 Y KYKLO PINE POINT B 1 1 5,007 1,387 8,350 80% 6,680 4,597 2,083 22% 1,619 1994 Y KLUA PINE POINT A 1 1 15,382 873 24,338 70% 17,037 15,117 1,919 43% 1,099 1973 Y KYKLO PINE POINT A 1 1 14,236 1,565 18,822 80% 15,058 13,664 1,393 25% 1,047 1989 Y SAHTANEH PINE POINT C 2 1 1,904 329 3,933 74% 2,910 1,674 1,236 29% 881 1994 Y OTHER AREAS PINE POINT D-092-E/094-I-12 1 0 13 - 1,997 40% 799 13 786 21% 620 1993 Y YOYO PINE POINT B 1 0 10,713 - 12,778 90% 11,500 10,713 787 25% 593 1979 Y SIERRA PINE POINT J 1 1 31,746 15,977 43,935 60% 26,361 25,498 863 36% 550 1980 Y Gilbert Laustsen Jung Associates Ltd. Page: 62 of 71

Table 3 Ekwan Study Area

Summary of British Columbia Oil and Gas Commission Reserves and Production

Prod. Stat's as of Nov. 30, 2002 BCOGC Reserves Estimates as of December 31, 2001 Prod Cumul. Last 3 mo. Initial Res. Cumul Rem Res. Rem Mrkbl Disc Well Well Gas Gas Rate OGIP Rec Raw Gas Prod Raw Gas Surf Reserves Year PT* Field Pool Name Count Count MMcf Mcfd (MMcf) Fac (MMcf) (MMcf) (MMcf) Loss (MMcf) SAHTANEH PINE POINT A 1 0 15,478 - 43,744 37% 16,185 15,478 707 26% 524 1977 Y SAHTANEH PINE POINT B 1 0 16,004 - 52,424 32% 16,776 16,004 771 34% 508 1993 Y KLUA PINE POINT F 1 1 4,248 386 5,061 90% 4,555 3,919 636 46% 345 1991 Y KYKLO PINE POINT C 1 0 2,278 - 3,088 80% 2,470 2,267 204 22% 158 1994 Y KLUA PINE POINT B 1 1 13,053 167 16,593 80% 13,275 13,008 267 45% 147 1978 Y KLUA PINE POINT C 1 0 6,276 - 7,844 81% 6,354 6,276 78 41% 46 1989 Y HELMET NORTH PINE POINT A 1 0 620 - 8,048 8% 644 620 24 20% 19 1967 J HELMET NORTH PINE POINT B 1 0 2 - 19,613 0% 20 2 18 21% 14 1979 J HELMET NORTH PINE POINT I 1 0 - - 11,908 80% 9,526 - 9,526 20% 7,638 1979 J HELMET NORTH PINE POINT F 1 0 - - 7,041 80% 5,633 - 5,633 19% 4,551 1981 J OTHER AREAS PINE POINT D-054-A/094-O-09 1 0 - - 6,314 80% 5,051 - 5,051 21% 3,992 1968 Y OTHER AREAS PINE POINT C-026-A/094-O-09 1 0 - - 5,946 80% 4,757 - 4,757 22% 3,703 1982 Y OTHER AREAS PINE POINT A-044-H/094-P-09 1 0 - - 5,803 65% 3,772 - 3,772 20% 3,009 1983 Y HELMET NORTH PINE POINT C 1 0 - - 4,294 80% 3,435 - 3,435 21% 2,728 1977 J HELMET NORTH PINE POINT E 1 0 - - 5,905 50% 2,952 - 2,952 18% 2,423 1980 J HELMET NORTH PINE POINT G 1 0 - - 4,364 60% 2,618 - 2,618 19% 2,129 1982 J HELMET NORTH PINE POINT J 1 0 - - 8,771 25% 2,193 - 2,193 15% 1,870 1982 J HELMET NORTH PINE POINT D 1 0 - - 1,950 80% 1,560 - 1,560 20% 1,247 1980 J OTHER AREAS PINE POINT C-006-H/094-P-09 1 1 - 342 1,987 65% 1,292 - 1,292 10% 1,160 1985 J HELMET NORTH PINE POINT H 1 0 - - 2,730 25% 682 - 682 19% 555 1988 J OTHER AREAS PINE POINT C-008-G/094-P-04 1 1 544 485 - 2001 Y KLUA PINE POINT 1 0 - - - 2001 Y KYKLO PINE POINT 1 0 - - - 2002 Y OTHER AREAS PINE POINT B-048-I/094-O-09 1 0 - - - 2001 Y OTHER AREAS PINE POINT B-085-A/094-O-09 1 0 - - - 2001 Y OTHER AREAS PINE POINT B-092-B/094-J-09 1 0 - - - 2002 Y MIDWINTER PINE POINT A 1 0 - - - 1983 J OTHER AREAS PINE POINT A-027-E/094-P-12 1 0 - - - 1980 Y OTHER AREAS PINE POINT B-047-L/094-I-14 1 0 - - - 1996 Y OTHER AREAS PINE POINT D-069-L/094-P-04 1 0 - - - 1995 Y SIERRA PINE POINT H 1 0 33 - - 1994 Y TSEA PINE POINT A 1 0 10 - - 1989 Y

Slave Point

HELMET SLAVE POINT A 14 2 131,326 824 241,961 67% 162,114 131,038 31,076 24% 23,704 1963 A SEXTET SLAVE POINT D 2 2 22,571 15,789 49,415 90% 44,473 17,315 27,159 19% 21,977 1996 A KOTCHO LAKE SLAVE POINT A 14 3 54,085 17,202 104,697 65% 68,053 48,847 19,206 22% 14,994 1959 C TSEA SLAVE POINT E 1 1 3,346 572 33,208 65% 21,585 3,147 18,438 25% 13,875 1994 C TSEA SLAVE POINT C 1 1 15,160 343 48,462 65% 31,500 15,004 16,496 23% 12,620 1980 C ELLEH NORTH SLAVE POINT A 2 0 3,278 - 22,310 80% 17,848 3,278 14,570 19% 11,741 1978 A CABIN SLAVE POINT B 2 1 29,918 2,040 67,289 65% 43,738 29,145 14,593 22% 11,343 1964 C LOUISE SLAVE POINT B 1 0 268 - 27,860 50% 13,930 268 13,662 24% 10,379 1995 C MEL SLAVE POINT A 1 1 59,486 4,858 106,481 65% 69,213 57,653 11,560 25% 8,682 1980 C SAHTANEH SLAVE POINT B 1 0 11,255 - 35,494 65% 23,071 11,255 11,816 30% 8,316 1976 A OTHER AREAS SLAVE POINT C-004-E/094-I-15 1 0 7 - 16,290 65% 10,588 7 10,581 23% 8,167 1974 A HELMET SLAVE POINT E 1 1 2,905 245 13,974 90% 12,576 2,853 9,723 21% 7,636 1995 A KOTCHO LAKE EAST SLAVE POINT C 6 1 29,909 264 114,077 30% 34,223 29,713 4,510 21% 3,573 1973 C YOYO SLAVE POINT A 2 1 430 19 6,693 65% 4,350 350 4,001 27% 2,902 1962 C HELMET SLAVE POINT B 4 1 14,707 64 36,018 50% 18,009 14,634 3,375 24% 2,560 1971 A BULLDOG SLAVE POINT A 1 0 4,565 - 11,448 65% 7,441 4,565 2,876 20% 2,310 1973 C LOUISE SLAVE POINT A 3 1 11,941 439 57,838 25% 14,459 11,788 2,671 22% 2,073 1965 C HOFFARD SLAVE POINT C 1 1 8,170 768 15,592 65% 10,135 7,882 2,253 21% 1,771 1989 C HELMET SLAVE POINT C 5 2 1,891 554 5,587 65% 3,632 1,669 1,963 20% 1,562 1971 A SAHTANEH SLAVE POINT C 1 1 5,384 110 11,218 65% 7,291 5,347 1,945 28% 1,401 1993 A SEXTET SLAVE POINT A 2 1 1,690 785 11,584 25% 2,896 1,480 1,416 21% 1,124 1971 A HOFFARD SLAVE POINT B 1 1 4,849 595 29,497 20% 5,899 4,644 1,256 16% 1,057 1969 C HOSSITL SLAVE POINT B 1 0 15 - 5,003 25% 1,251 15 1,235 22% 969 1977 C SEXTET SLAVE POINT B 3 1 11,438 929 18,794 65% 12,216 11,152 1,065 20% 855 1994 A PEGGO-PESH SLAVE POINT H 2 0 1,925 - 3,833 65% 2,491 1,925 566 22% 442 1981 A SIERRA SLAVE POINT C 1 0 3,679 - 9,512 41% 3,900 3,679 221 23% 170 1986 C HOFFARD SLAVE POINT A 1 1 4,654 416 13,352 35% 4,673 4,503 170 21% 135 1965 C SAHTANEH SLAVE POINT D 1 0 460 - 11,351 5% 568 460 107 27% 78 1994 A PETITOT RIVER SLAVE POINT A 4 0 17,744 - 98,871 18% 17,797 17,744 53 21% 41 1959 C EKWAN SLAVE POINT A 1 0 801 - 11,242 8% 843 801 42 22% 33 1977 A JUNIOR SLAVE POINT A 1 0 6,996 - 10,947 64% 7,028 6,996 32 19% 26 1962 A TSEA SLAVE POINT B 1 0 9,414 - 23,488 40% 9,442 9,414 28 23% 21 1964 C HOSSITL SLAVE POINT G 1 0 1,827 - 26,061 7% 1,850 1,827 23 22% 18 1989 C Gilbert Laustsen Jung Associates Ltd. Page: 63 of 71

Table 3 Ekwan Study Area

Summary of British Columbia Oil and Gas Commission Reserves and Production

Prod. Stat's as of Nov. 30, 2002 BCOGC Reserves Estimates as of December 31, 2001 Prod Cumul. Last 3 mo. Initial Res. Cumul Rem Res. Rem Mrkbl Disc Well Well Gas Gas Rate OGIP Rec Raw Gas Prod Raw Gas Surf Reserves Year PT* Field Pool Name Count Count MMcf Mcfd (MMcf) Fac (MMcf) (MMcf) (MMcf) Loss (MMcf) PEGGO-PESH SLAVE POINT A 1 0 328 - 26,969 1% 351 328 23 21% 18 1982 A CABIN SLAVE POINT E 1 0 1,503 - 36,220 4% 1,521 1,503 18 24% 14 1982 C HOSSITL SLAVE POINT H 1 0 4,494 - 23,248 19% 4,510 4,494 16 21% 13 1992 C CABIN SLAVE POINT D 2 0 3,116 - 18,414 17% 3,130 3,116 14 12% 13 1977 C HOSSITL SLAVE POINT F 1 0 3,370 - 14,152 24% 3,382 3,370 13 21% 10 1989 C HOSSITL SLAVE POINT I 1 0 3,775 - 24,280 16% 3,788 3,775 12 21% 10 1994 C EKWAN SLAVE POINT B 1 0 1,335 - 3,955 34% 1,345 1,335 10 14% 9 1978 A HOSSITL SLAVE POINT E 2 0 4,230 - 13,009 33% 4,241 4,230 11 22% 9 1988 C KOTCHO LAKE EAST SLAVE POINT B 2 0 5,048 - 25,045 20% 5,059 5,048 11 22% 8 1973 C KOTCHO LAKE SLAVE POINT C 1 0 3,911 - 11,633 34% 3,920 3,911 10 24% 7 1972 C JUNIOR SLAVE POINT B 2 0 22 - 10,217 0% 31 22 9 18% 7 1963 A DILLY SLAVE POINT A 1 0 1,460 - 12,317 12% 1,466 1,460 6 20% 5 1962 C CABIN SLAVE POINT A 2 0 2,996 - 15,193 20% 3,002 2,996 5 24% 4 1969 C CABIN SLAVE POINT C 2 0 10,343 - 26,809 39% 10,348 10,343 5 22% 4 1963 C JUNIOR SLAVE POINT D 1 0 613 - 3,905 16% 617 613 4 20% 3 1977 A ELLEH NORTH SLAVE POINT B 1 0 216 - 3,982 6% 219 216 3 18% 2 1979 A TSEA SLAVE POINT A 2 0 1,875 - 18,236 10% 1,878 1,875 3 24% 2 1961 C HOFFARD SLAVE POINT D 2 1 2,508 375 23,863 10% 2,386 2,383 3 21% 2 1990 C PEGGO-PESH SLAVE POINT C 1 0 1,041 - 3,768 28% 1,044 1,041 2 21% 2 1987 A SIERRA SLAVE POINT A 1 0 9,541 - 27,582 35% 9,543 9,541 2 24% 2 1976 C HOSSITL SLAVE POINT A 1 0 8,622 - 54,928 16% 8,624 8,622 2 19% 2 1968 C PEGGO-PESH SLAVE POINT I 1 0 25 - 2,042 1% 27 25 2 23% 1 1968 A OTHER AREAS SLAVE POINT D-054-A/094-O-09 1 0 - - 17,080 65% 11,102 - 11,102 22% 8,642 1968 C SHEKILIE SLAVE POINT A 1 1 - - 14,003 65% 9,102 - 9,102 18% 7,459 1966 A PEGGO-PESH SLAVE POINT E 1 0 - - 9,653 65% 6,274 - 6,274 23% 4,828 1971 A ELLEH SLAVE POINT A 1 0 - - 6,495 75% 4,871 - 4,871 16% 4,084 1981 C OTHER AREAS SLAVE POINT D-066-I/094-I-16 1 0 - - 5,074 65% 3,298 - 3,298 20% 2,624 1980 A TSEA SLAVE POINT D 1 0 - - 4,845 65% 3,149 - 3,149 22% 2,469 1988 C SAHTANEH SLAVE POINT A 1 0 - - 3,391 74% 2,509 - 2,509 23% 1,925 1977 A PEGGO-PESH SLAVE POINT G 1 0 - - 3,698 65% 2,404 - 2,404 22% 1,878 1981 A PEGGO-PESH SLAVE POINT F 1 0 - - 2,543 65% 1,653 - 1,653 23% 1,272 1972 A PEGGO-PESH SLAVE POINT D 1 0 - - 2,240 65% 1,456 - 1,456 14% 1,246 1988 A HELMET NORTH SLAVE POINT A 1 0 - - 5,187 25% 1,297 - 1,297 16% 1,085 1969 C HOSSITL SLAVE POINT D 1 0 - - 2,140 25% 535 - 535 26% 397 1978 C SEXTET SLAVE POINT E 1 1 1,082 4,400 - 2002 A HOFFARD SLAVE POINT E 1 1 61 56 - 1990 C EKWAN SLAVE POINT 1 0 - - - 2002 A KLUA SLAVE POINT 1 0 - - - 2002 C KOTCHO LAKE SLAVE POINT 2 0 - - - 2001 C OTHER AREAS SLAVE POINT A-009-L/094-P-03 1 0 - - - 2002 C OTHER AREAS SLAVE POINT C-035-D/094-P-12 1 0 - - - 2002 C OTHER AREAS SLAVE POINT D-068-E/094-P-03 1 0 - - - 2002 C SEXTET SLAVE POINT F 1 0 7 - - 2002 A ELLEH NORTH SLAVE POINT 1 0 - - - 1996 A HELMET NORTH SLAVE POINT B 1 0 - - - 1976 C HELMET SLAVE POINT 1 0 - - - 1996 A OTHER AREAS SLAVE POINT A-005-K/094-I-10 1 0 9 - - 1995 A OTHER AREAS SLAVE POINT A-097-K/094-I-12 1 0 - - - 1970 A OTHER AREAS SLAVE POINT B-062-H/094-J-01 1 0 0 - - 1995 A OTHER AREAS SLAVE POINT C-100-K/094-I-12 1 0 - - - 1985 A OTHER AREAS SLAVE POINT D-018-K/094-P-02 1 0 2 - - 1967 A OTHER AREAS SLAVE POINT D-070-G/094-I-11 1 0 4 - - 1996 A OTHER AREAS SLAVE POINT D-073-D/094-I-09 1 0 12 - - 1995 A PEGGO-PESH SLAVE POINT B 1 0 - - - 1983 A SEXTET SLAVE POINT 1 0 - - - 1997 A

Total 1,140 624 4,639,989 570,739 8,593,644 6,296,024 4,421,404 1,874,620 81% 1,520,718

PT* - Play Type : A- Adsett ; C- Clarke Lake ; J - July Lake ; Y - Yoyo

Gilbert Laustsen Jung Associates Ltd. Page: 64 of 71

Table 4 Ekwan Supply Study Jean Marie - Summary of Results

Gas Reserve Summary

Producing Recovery Factor Ultimate Prod. Reserves (BCF Raw) Remaining Prod. Reserves (BCF Raw) Proved Proved + Proved + Cumulative Proved + OGIP Proved + Probable+ Proved + Probable+ Production Proved + Probable+ Region BCF raw Proved Probable Possible Proved Probable Possible (BCF Raw) Proved Probable Possible

Cabin 0 0.0% 0.0% 0.0% 0 0 0 0 0 0 0 Conroy 0 0.0% 0.0% 0.0% 0 0 0 0 0 0 0 Ekwan 174 17.0% 19.0% 21.0% 30 33 36 7 23 26 29 Gunnell/Cabin 618 35.0% 40.0% 45.0% 216 247 278 56 161 192 222 Helmet 305 84.0% 86.0% 90.0% 256 262 274 172 84 90 103 Midwinter 443 88.0% 90.0% 92.0% 389 398 407 259 131 140 148 Peggo 432 80.0% 85.0% 90.0% 345 367 389 154 192 213 235 Sierra 358 25.0% 30.0% 35.0% 89 107 125 17 72 90 108

Total 2328 57.0% 60.8% 64.8% 1326 1415 1510 664 662 751 846

Prod. + NonProd. Recovery Factor Ultimate Reserves (BCF Raw) Non-Producing Reserves (BCF Raw)

Proved Proved + Proved + Proved + OGIP Proved + Probable+ Proved + Probable+ Proved + Probable+ BCF raw Proved Probable Possible Proved Probable Possible Proved Probable Possible

Cabin 8 60.0% 65.0% 70.0% 5 5 6 5 5 6 Conroy 0 0.0% 0.0% 0.0% 0 0 0 0 0 0 Ekwan 174 40.0% 45.0% 50.0% 70 78 87 40 45 50 Gunnell/Cabin 618 60.0% 65.0% 70.0% 371 401 432 154 154 154 Helmet 305 86.0% 90.0% 92.0% 262 274 280 6 12 6 Midwinter 443 90.0% 92.0% 92.0% 398 407 407 9 9 0 Peggo 432 85.0% 90.0% 92.0% 367 389 397 22 22 9 Sierra 358 60.0% 65.0% 75.0% 215 233 268 125 125 143

Total 2337 72.2% 76.5% 80.4% 1687 1788 1878 361 373 369

Prob. NonProd Recovery Factor Ultimate Prob. NonProd. Res. (BCF Raw) Total Non-Prod. Reserves (BCF Raw) Probable Proved + Proved + Proved + OGIP Proved + Probable+ Proved + Probable+ Proved + Probable+ BCF raw Proved Probable Possible Proved Probable Possible Proved Probable Possible

Cabin 43 0.0% 40.0% 70.0% 0 17 30 5 23 36 Conroy * 118 0.0% 0.0% 20.0% 0 0 24 0 0 24 Ekwan 67 0.0% 25.0% 50.0% 0 17 33 40 62 84 Gunnell/Cabin 98 0.0% 40.0% 70.0% 0 39 69 154 194 223 Helmet 32 0.0% 80.0% 90.0% 0 26 29 6 38 35 Midwinter 46 0.0% 80.0% 90.0% 0 37 41 9 46 41 Peggo 156 0.0% 80.0% 90.0% 0 125 141 22 147 149 Sierra 366 0.0% 50.0% 75.0% 0 183 274 125 308 418

Total 927 0 444 642 361 817 1011 Total Probable 809 Note: * Conroy OGIP classified as possible Proved + Prob. 3146 Pv+Pb+Ps 3264

Ultimate Reserves (BCF Raw) Remaining Reserves (BCF Raw) Remaining Reserves (BCF Sales) * Proved + Proved + Proved + Proved + Probable+ Proved + Probable+ Proved + Probable+ Proved Probable Possible Proved Probable Possible Proved Probable Possible

Cabin 5 23 36 5 23 36 5 21 34 Conroy 0 0 24 0 0 24 0 0 22 Ekwan 70 95 120 62 88 113 59 83 107 Gunnell/Cabin 371 441 501 315 385 446 296 362 419 Helmet 262 300 309 90 129 138 85 121 130 Midwinter 398 444 449 140 185 190 131 174 178 Peggo 367 514 538 213 360 384 200 338 361 Sierra 215 416 543 197 398 526 186 374 494

Total 1687 2232 2520 1023 1568 1856 962 1474 1745

Gilbert Laustsen Jung Associates Ltd. Page: 65 of 71

Table 4 Ekwan Supply Study Jean Marie - Summary of Results

Contingent and Undiscovered Resource Summary

Contingent Resources (BCF Raw) Undiscovered Resources (BCF Raw) Contingent + Undiscovered Resources(BCF Raw) Low Best High Low Best High Low Best High Estimate Estimate Estimate Estimate Estimate Estimate Estimate Estimate Estimate

Cabin 39 56 76 5 7 11 44 64 86 Conroy 0 70 175 0 56 210 0 126 386 Ekwan 16 23 32 39 87 145 54 110 177 Gunnell/Cabin 7 9 13 64 103 148 70 113 161 Helmet 28 39 50 24 37 51 52 76 101 Midwinter 14 19 24 62 95 127 76 115 152 Peggo 48 68 87 58 93 127 107 161 214 Sierra 98 141 204 77 124 191 174 265 395

Total 249 427 661 328 604 1010 577 1030 1671

Total Resources Summary

Total Resources(BCF Raw) Remaining Resources (BCF Raw) Remaining Resources (BCF Sales) Best Best Best Minimum Estimate Maximum Minimum Estimate Maximum Minimum Estimate Maximum

Cabin 49 86 122 49 86 122 46 81 115 Conroy 0 126 409 0 126 409 0 119 385 Ekwan 124 205 297 117 198 290 110 186 273 Gunnell/Cabin 441 553 662 385 498 607 362 468 570 Helmet 314 377 410 142 205 239 134 193 224 Midwinter 475 559 600 216 300 341 203 282 321 Peggo 474 675 752 320 521 598 301 490 562 Sierra 389 681 938 372 664 921 349 624 865

Total 2264 3262 4191 1600 2598 3527 1504 2442 3315

Note: Average surface loss of 6 percent used for all regions

Gilbert Laustsen Jung Associates Ltd. Table 5 Ekwan Study Area Summary of Undiscovered Resources (OGIP)

Play Type Discovered * Undiscovered - Low Estimate Percentage of Undiscovered - High Estimate Percentage of Undiscovered - Best Estimate Percentage of OGIP # Pools avg size OGIP # Pools avg size Median size Total Resource OGIP # Pools avg size Median size Total Resource OGIP # Pools avg size Total Resource (BCF) (BCF) (BCF) (BCF) (BCF) Undiscovered (BCF) (BCF) (BCF) Undiscovered (BCF) (BCF) Undiscovered Bluesky 52.7 13 4.1 30.3 28 1.08 0.91 37% 66.6 46 1.45 1.08 56% 66.6 46 1.45 56% Debolt 80.4 19 4.2 104.0 61 1.71 1.05 56% 165.4 86 1.92 1.04 67% 150.1 80 1.88 65% Slave Point, Adsett 671.7 29 23.2 159.3 41 3.89 3.04 19% 351.7 65 5.41 4.50 34% 255.5 53 4.82 28% Slave Point, Clarke Lake 1,197.6 42 28.5 274.4 45 6.10 2.14 19% 601.4 69 8.72 2.57 33% 274.4 45 6.10 19% Pine Point, July Lake 86.3 13 6.6 26.9 19 1.41 1.09 24% 76.9 48 1.60 1.24 47% 26.9 19 1.41 24% Pine Point, Yoyo 5,056.4 36 140.5 238.2 32 7.44 1.83 4% 830.4 49 16.95 2.58 14% 534.3 41 13.03 10% Subtotals 7,145.2 152 833.2 226 10% 2,092.5 363 23% 1,307.8 284 15%

Jean Marie 2337.0 929.0 28% 2671.0 53% 1691.0 42% Volumetric Analysis **

Total 9,482.2 152 1,762.2 226 16% 4,763.5 363 33% 2,998.8 284 24%

* BRITISH COLUMBIA OIL & GAS COMMISSION (End 2001)

** Total Proved volumetric OGIP determine using GLJ & Encana wellbore parameters for wells drilled to year end 2002. (Jean Marie Undiscovered Resource estimate includes Contingent Resources)

Additional gas plays exist in the Baldonnel, Banff, Detrital, Doig, Dunvegan, Kakisa, Undefined Mississippian, Montney, Pekisko, Shunda and Sulphur Point. Although minor, these are not included in the above totals. Page: 66 of 71

Gilbert Laustsen Jung Associates Ltd. Table 6 Ekwan Study Area Total Gas Resources (BCF)

Zone Resource Type/Group Estimated Initial Resources* Remaining Raw Gas Resources* Remaining Sales Gas Resources* Low Best High Cumulative Low Best High Low Best High Estimate Estimate Estimate Production Estimate Estimate Estimate Estimate Estimate Estimate

Jean Marie Developed Reserves 1,326 1,415 1,510 664 662 751 846 622 706 795 Jean Marie NonProd+Undevel Reserves 361 817 1,011 361 817 1,011 340 768 950 Jean Marie Contingent Resources 249 427 661 249 427 661 234 401 621 Jean Marie Undiscovered Resources 328 604 1,010 328 604 1,010 308 567 949 Subtotal 2,264 3,262 4,191 664 1,600 2,598 3,527 1,504 2,443 3,316

Miss-Debolt BC OGC Identified Producing Pools 180 190 220 34 146 156 186 126 134 160 Miss-Debolt BC OGC Identified NonProducing Pools 3 3 3 - 3 3 3 3 3 3 Miss-Debolt Other Producing Pools 6 7 7 3 4 4 4 3 3 4 Miss-Debolt Recent Additions 3 5 6 0 3 5 6 3 4 5 Miss-Debolt Undiscovered Resources 19 54 88 - 19 54 88 16 45 74 Subtotal 211 259 325 36 175 222 288 150 190 246

Other Zones BC OGC Identified Producing Pools 89 91 95 63 26 28 32 22 23 27 Other Zones BC OGC Identified NonProducing Pools 3 3 3 - 3 3 3 2 2 2 Other Zones Other Producing Pools 16 18 20 6 10 12 14 8 10 12 Other Zones Recent Additions 2 5 5 0 2 5 5 2 4 4 Other Zones Undiscovered Resources 5 19 29 - 5 19 29 4 16 24 Subtotal 115 136 152 69 46 67 83 38 55 68

Pine Point BC OGC Identified Producing Pools 3,972 4,020 4,050 3,338 634 682 712 466 501 524 Pine Point BC OGC Identified NonProducing Pools 43 43 43 0 43 43 43 35 35 35 Pine Point Other Producing Pools 2 2 2 1 1 1 1 1 1 1 Pine Point Recent Additions 4 8 10 - 4 8 10 3 6 8 Pine Point Undiscovered Resources 145 325 521 - 145 325 521 112 250 401 Subtotal 4,167 4,399 4,627 3,339 828 1,060 1,288 617 794 969

Slave Point BC OGC Identified Producing Pools 670 720 750 548 122 172 202 94 133 156 Slave Point BC OGC Identified NonProducing Pools 48 48 48 - 48 48 48 38 38 38 Slave Point Other Producing Pools 10 13 15 1 9 11 14 7 9 11 Slave Point Recent Additions 5 8 14 0 5 8 14 4 6 11 Slave Point Undiscovered Resources 95 168 222 - 95 168 222 74 132 175 Subtotal 827 956 1,049 549 278 407 500 217 318 390

Total Developed Reserves 6,271 6,475 6,669 4,657 1,614 1,818 2,012 1,350 1,521 1,689 Total NonProd+Undevel Reserves 473 940 1,143 0 473 940 1,143 429 866 1,056 Total Contingent Resources 249 427 661 - 249 427 661 234 401 621 Total Undiscovered Resources 591 1,170 1,871 - 591 1,170 1,871 514 1,011 1,623 Page: 67 of 71 Grand Total Reserves Plus Resources 7,584 9,012 10,344 4,657 2,927 4,355 5,686 2,527 3,800 4,989

*"With the exception of Undiscovered and Contingent Resources", estimates reflect "Reserves" Gilbert Laustsen Jung Associates Ltd. Table 7 Ekwan Study Area Gas Supply Forecast (Low Case - MMcfd Sales)

History Forecast

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Jean Marie Developed Reserves 127 142 156 174 205 236 247 219 185 159 137 120 106 94 83 75 67 61 55 50 45 40 36 32 29 26 24 NonProd+Undev Reserves 16 44 66 84 94 87 73 61 52 45 39 34 30 27 23 21 18 16 14 12 Contingent Resources 11 30 45 58 65 60 50 42 36 31 27 24 21 18 16 14 12 11 10 9 Undiscovered 15 39 60 76 86 79 66 56 48 41 35 31 27 24 21 19 16 14 13 11 127 142 156 174 205 236 247 261 298 330 355 365 333 283 242 211 184 162 144 128 113 101 89 79 71 63 56 Miss-Debolt BC OGC Identified Producing Pools 47 41 35 31 27 23 20 17 15 13 11 10 8 7 6 5 5 4 4 3 BC OGC Identified NonProducing Pools 2 1 1 1 1 1 1 0 0 0 0 ------Other Producing Pools 5 2 1 0 0 0 ------Recent Additions 1 1 1 1 1 1 1 0 0 0 0 0 0 0 ------Undiscovered 1 2 2 3 3 3 3 3 3 3 3 2 2 2 2 2 2 2 - - - 0 0 5 3 24 47 55 47 40 36 31 27 24 21 18 16 14 12 11 10 8 8 7 6 4 3 Other Zones BC OGC Identified Producing Pools 9 8 7 6 5 4 4 3 3 2 2 2 1 1 1 1 - - - - BC OGC Identified NonProducing Pools 1 1 1 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Other Producing Pools 4 4 3 2 2 2 1 1 1 1 1 1 0 ------Recent Additions 1 1 0 0 0 0 0 0 0 0 0 0 0 ------Undiscovered 1 1 1 1 1 1 1 1 1 1 1 0 0 0 0 0 0 0 - - 9 6 5 6 11 14 13 16 14 12 10 9 8 7 6 5 4 4 3 2 2 2 1 0 0 0 0 Pine Point BC OGC Identified Producing Pools 136 122 109 97 87 78 70 63 56 50 45 40 36 32 29 26 23 21 19 17 BC OGC Identified NonProducing Pools 9 8 8 7 6 6 5 5 4 4 4 3 3 3 2 2 2 2 2 2 Other Producing Pools 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Recent Additions 1 1 1 1 1 1 1 1 0 0 0 0 0 0 0 0 0 0 0 - Undiscovered 2 4 6 8 10 12 14 16 15 13 12 11 10 9 9 8 7 7 6 6 219 190 206 202 181 177 155 148 135 123 113 104 97 90 84 76 68 61 55 50 45 40 36 33 30 27 24 Slave Point BC OGC Identified Producing Pools 36 31 27 23 20 17 15 13 11 10 8 7 6 5 5 4 4 3 3 2 BC OGC Identified NonProducing Pools 10 9 8 7 7 6 6 5 5 4 4 4 3 3 3 2 2 2 2 2 Other Producing Pools 4 3 2 2 2 1 1 1 1 1 0 0 0 0 0 0 0 0 0 0 Recent Additions 1 1 1 1 1 1 1 1 1 0 0 0 0 0 0 0 0 0 0 0 Undiscovered 2 4 6 8 10 12 11 10 9 9 8 7 7 6 6 5 5 5 4 4 51 41 24 20 22 31 41 52 48 44 41 39 38 33 30 27 24 21 19 17 15 14 12 11 10 9 8 Total Developed Reserves 127 142 156 174 205 236 247 460 395 344 299 263 232 205 181 162 144 129 115 102 91 81 73 64 57 51 46 NonProd+Undev Reserves ------40 66 86 102 111 103 87 74 64 55 48 43 38 33 29 26 23 20 18 16 Contingent Resources ------11 30 45 58 65 60 50 42 36 31 27 24 21 18 16 14 12 11 10 9 Undiscovered ------21 50 75 96 109 107 95 85 75 66 59 53 47 43 38 34 31 28 23 21

Grand Total 406 378 391 407 422 481 502 532 541 550 555 548 502 437 383 337 297 263 234 208 185 165 147 131 116 102 90

*"With the exception of Contingent and Undiscovered", estimates reflect "Reserves" Page: 68 of 71

Gilbert Laustsen Jung Associates Ltd. Table 8 Ekwan Study Area Gas Supply Forecast (Best Estimate Case - MMcfd Sales)

History Forecast

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Jean Marie Developed Reserves 127 142 156 174 205 236 247 220 188 163 143 126 112 100 90 81 74 67 62 56 51 47 43 39 35 32 29 NonProd+Undev Reserves 29 78 117 150 177 197 186 155 131 112 96 84 74 65 57 50 44 39 34 30 Contingent Resources 15 41 61 78 92 103 97 81 69 58 50 44 39 34 30 26 23 20 18 16 Undiscovered 21 57 87 111 131 146 138 115 97 83 71 62 55 48 42 37 33 29 25 22 127 142 156 174 205 236 247 285 364 428 482 526 558 521 441 378 327 285 252 224 198 176 156 139 123 110 97 Miss-Debolt ------BC OGC Identified Producing Pools ------56 49 43 37 32 28 25 21 19 16 14 12 11 5 ------BC OGC Identified NonProducing Pools ------2 2 1 1 1 1 0 ------Other Producing Pools ------6 3 1 ------Recent Additions ------1 1 1 1 1 1 1 1 1 1 1 1 0 ------Undiscovered ------2 3 4 5 6 7 8 7 7 6 6 5 5 5 4 4 4 3 3 3 - 0 0 5 3 24 47 67 57 50 44 40 37 34 30 26 23 21 18 16 9 4 4 4 3 3 3 Other Zones ------BC OGC Identified Producing Pools ------11 10 8 7 6 5 5 4 4 3 0 ------BC OGC Identified NonProducing Pools ------1 1 1 1 1 0 0 0 0 0 0 0 0 0 0 0 - - - - Other Producing Pools ------5 4 4 3 3 2 2 2 1 ------Recent Additions ------1 1 1 1 1 1 1 1 1 1 1 1 ------Undiscovered ------1 2 3 4 4 3 3 3 3 2 2 2 2 2 1 1 1 1 1 1 9 6 5 6 11 14 13 19 18 17 16 14 13 11 10 8 6 3 3 2 2 2 1 1 1 1 1 Pine Point ------BC OGC Identified Producing Pools ------188 169 153 138 124 112 101 91 82 74 66 60 18 ------BC OGC Identified NonProducing Pools ------11 10 9 9 8 7 6 6 5 5 4 4 4 3 3 - - - - - Other Producing Pools ------0 0 0 0 0 0 0 0 0 0 0 0 0 ------Recent Additions ------2 2 2 2 1 1 1 1 1 1 1 1 1 0 ------Undiscovered ------2 5 10 15 20 25 30 35 40 45 41 37 34 31 28 26 23 21 20 18 219 190 206 202 181 177 155 204 187 174 163 153 145 139 133 128 125 113 102 57 34 31 26 23 21 20 18 Slave Point ------BC OGC Identified Producing Pools ------52 46 41 37 33 29 26 24 21 19 17 15 4 ------BC OGC Identified NonProducing Pools ------12 11 10 9 9 8 7 6 6 5 5 4 4 4 3 - - - - - Other Producing Pools ------5 4 3 3 2 2 2 2 1 0 ------Recent Additions ------2 2 2 2 1 1 1 1 1 1 1 1 1 0 ------Undiscovered ------2 4 7 9 12 15 17 19 20 20 18 17 15 14 13 12 11 10 9 8 51 41 24 20 22 31 41 73 67 64 60 57 56 53 52 49 45 41 37 24 18 16 12 11 10 9 8 Total ------Developed Reserves 127 142 156 174 205 236 247 543 474 416 368 327 292 260 233 209 186 165 149 89 56 47 43 39 35 32 29 NonProd+Undev Reserves ------62 108 145 175 200 218 205 172 146 126 109 96 83 73 63 50 44 39 34 30 Contingent Resources ------15 41 61 78 92 103 97 81 69 58 50 44 39 34 30 26 23 20 18 16 Undiscovered ------28 71 111 144 172 196 196 179 166 156 138 123 111 99 89 80 72 65 58 52

Grand Total 406 378 391 407 422 481 502 648 694 732 765 791 808 758 665 590 526 462 412 322 262 229 199 178 159 142 127

*"With the exception of Contingent and Undiscovered", estimates reflect "Reserves" Page: 69 of 71

Gilbert Laustsen Jung Associates Ltd. Table 9 Ekwan Study Area Gas Supply Forecast (Maximum Case - MMcfd Sales)

History Forecast

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Jean Marie Developed Reserves 127 142 156 174 205 236 247 221 191 167 147 131 117 106 96 87 80 73 67 62 57 52 48 44 41 37 34 Undeveloped Reserves 36 96 144 184 217 244 231 192 162 138 119 103 91 80 70 62 54 48 42 37 Contingent Resources 23 63 94 121 142 160 151 126 106 90 78 68 59 52 46 40 36 31 28 24 Undiscovered 36 96 144 184 217 244 231 192 162 138 119 103 91 80 70 62 54 48 42 37 127 142 156 174 205 236 247 316 445 550 636 708 765 720 606 517 446 388 341 303 269 239 212 189 168 149 133 Miss-Debolt ------BC OGC Identified Producing Pools ------58 51 46 40 36 32 28 25 23 20 18 16 14 13 11 8 - - - - BC OGC Identified NonProducing Pools ------2 2 1 1 1 1 0 ------Other Producing Pools ------6 3 1 ------Recent Additions ------2 2 1 1 1 1 1 1 1 1 1 1 1 ------Undiscovered ------2 4 6 8 10 12 14 16 15 13 12 11 10 9 9 8 7 7 6 5 - 0 0 5 3 24 47 69 61 55 51 48 46 44 42 38 34 31 28 25 22 20 16 7 7 6 5 Other Zones ------BC OGC Identified Producing Pools ------11 10 9 8 7 6 5 5 4 4 3 2 ------BC OGC Identified NonProducing Pools ------1 1 1 1 1 0 0 0 0 0 0 0 0 0 0 0 - - - - Other Producing Pools ------5 5 4 4 3 3 2 2 2 2 0 ------Recent Additions ------1 1 1 1 1 1 1 1 1 1 1 1 ------Undiscovered ------1 2 3 4 4 4 4 4 4 3 3 3 2 2 2 2 2 2 1 1 9 6 5 6 11 14 13 20 18 18 17 15 14 13 12 11 10 7 5 3 2 2 2 2 2 1 1 Pine Point ------BC OGC Identified Producing Pools ------191 173 156 141 127 115 104 94 85 77 69 63 39 ------BC OGC Identified NonProducing Pools ------11 10 9 9 8 7 6 6 5 5 4 4 4 3 3 - - - - - Other Producing Pools ------0 0 0 0 0 0 0 0 0 0 0 0 0 ------Recent Additions ------3 2 2 2 2 2 2 1 1 1 1 1 1 0 ------Undiscovered ------2 6 12 18 24 30 36 42 48 54 60 60 60 55 50 45 41 37 34 31 219 190 206 202 181 177 155 208 192 180 170 161 154 148 144 140 137 135 128 104 58 53 45 41 37 34 31 Slave Point ------BC OGC Identified Producing Pools ------57 51 46 41 37 34 30 27 24 22 20 18 16 4 ------BC OGC Identified NonProducing Pools ------12 11 10 9 9 8 7 6 6 5 5 4 4 4 3 - - - - - Other Producing Pools ------5 4 4 3 3 2 2 2 2 1 1 0 ------Recent Additions ------4 3 3 3 2 2 2 2 2 2 1 1 1 1 0 - - - - - Undiscovered ------2 5 8 10 14 17 20 25 25 25 25 23 21 19 17 16 15 13 12 11 51 41 24 20 22 31 41 80 75 71 67 65 63 61 62 59 55 52 47 42 27 20 16 15 13 12 11 Total ------Developed Reserves 127 142 156 174 205 236 247 554 488 433 385 345 309 279 251 227 206 185 165 131 73 63 56 44 41 37 34 Undeveloped Reserves ------71 128 174 211 242 266 251 210 178 153 132 116 102 89 76 62 54 48 42 37 Contingent Resources ------23 63 94 121 142 160 151 126 106 90 78 68 59 52 46 40 36 31 28 24 Undiscovered ------43 113 173 224 269 307 305 279 253 234 219 200 184 165 148 133 119 107 96 86

Grand Total 406 378 391 407 422 481 502 692 792 874 940 998 1,042 987 866 764 682 614 548 476 379 334 292 253 227 203 182

*"With the exception of Contingent and Undiscovered", estimates reflect "Reserves" Page: 70 of 71

Gilbert Laustsen Jung Associates Ltd. Page: 71 of 71

REFERENCES

1. HYDROCARBON AND BY-PRODUCT RESERVES IN BRITISH COLUMBIA, 2001 Engineering and Geology Branch, Oil and Gas Commission

2. DEVONIAN GAS RESOURCES OF THE WESTERN CANADA SEDIMENTARY BASIN Reinson G.E., Lee P.J., Warters W., Osadetz K.G., Bell L.L., Price P.R., Trollope F., Campbell R.I., Barclay J.E. Geological Survey of Canada, Bulletin 452

3. NATURAL GAS POTENTIAL IN CANADA Canadian Gas Potential Committee, 2001

4. NATURAL GAS ASSESSMENT, NORTHEAST BRITISH COLUMBIA National Energy Board, Calgary, 1994 (revised 1999).

5. AND GAS RESOURCES OF THE WESTERN CANADA SEDIMENTARY BASIN, INTERIOR PLAINS Barclay J.E., Holmstrom G.D., Lee P.J., Campbell R.I., and Reinson G.E. Geological Survey of Canada, Bulletin 515

6. NORTHEAST BRITISH COLUMBIA NATURAL GAS ASSESSMENT, 1992-1997 National Energy Board, October 2000.

Gilbert Laustsen Jung Associates Ltd.