RESERVE AND ECONOMIC EVALUATION
GAS PROPERTIES
Owned by
CAMFLO INTERNATIONAL INC.
November 1, 2003
November 19, 2003
Camflo International Inc.
1205, 789 West Pender Street
Vancouver, BC
V6C 1H2
Attention: Mr. Tom Doyle
Dear Sir:
Re:
Camflo International Inc.
Reserve and Economic Evaluation – November 1, 2003
In accordance with your authorization we have performed a reserve and economic evaluation of two gas properties owned by Camflo International Inc. (the "Company") in Alberta for an effective date of November 1, 2003 (as of October 31, 2003).
This evaluation has been carried out in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook "COGEH") prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining Metallurgy and Petroleum (Petroleum Society). The report has been prepared or supervised by a "Qualified Reserves Evaluator" as demonstrated on the accompanying Certificate of Qualifications of the author(s).
The EXECUTIVE SUMMARY contains the results of this reserve and economic evaluation presented in a form consistent with the requirements of Form 51-101 F1 Part 2, Item 2.2 (Forecast Prices and Costs) and Item 2.1 (Constant Prices and Costs). The Forecast Prices and Constant Prices of our benchmark products are also presented. For the purpose of this report the "After Tax" analysis, consolidations by product type and reserve reconciliation were not included.
The SUMMARY OF RESERVES AND ECONOMICS complements the Executive Summary, including values at the property level and the consolidated cash flows for each accumulating reserve category. The net present values presented in this report do not necessarily represent the fair market value of the reserves evaluated in this report.
The SCOPE of REPORT contains the authorization and purpose of the report and describes the methodology and economic parameters used in the preparation of this report.
The DISCUSSION contains a description of the interests and burdens, reserves and geology, production forecasts, product prices, capital and operating costs and a map of each property. The economic results and cash flow forecasts (before income tax and ARTC) are also presented on an entity and property summary level.
Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material. We have no responsibility to update our report for events and circumstances which may have occurred since the preparation date of this report.
Prior to public disclosure of any information contained in this report, or our name as author, our written consent must be obtained, as to the information being disclosed and the manner in which it is presented. This report may not be reproduced, distributed or made available for use by any other party without our written consent and may not be reproduced for distribution at any time without the complete context of the report, unless otherwise reviewed and approved by us.
It has been a pleasure to prepare this report and the opportunity to have been of service is appreciated.
Yours very truly,
Chapman Petroleum Engineering Ltd.
C. W. Chapman P. Eng.,
President
J.S. Deck, C.E.T.,
Associate
jsd/sil/3558
CERTIFICATE OF QUALIFICATION
I, C. W. CHAPMAN, P. Eng., Professional Engineer of the City of Calgary, Alberta, hereby certify:
1.
THAT I am a registered Professional Engineer in the Province of Alberta and a member of the Australasian Institute of Mining and Metallurgy, and I reside at 230 Mt. Cascade Place, S.E., Calgary, Alberta.
2.
THAT I graduated from the University of Alberta with a Bachelor of Science degree in Mechanical Engineering in 1971.
3.
THAT I have been employed in the petroleum industry since graduation by various companies and have been directly involved in reservoir engineering, petrophysics, operations, and evaluations during that time.
4.
THAT I have in excess of 25 years in the conduct of evaluation and engineering studies relating to oil & gas fields in Canada and around the world.
5.
THAT I participated directly in the evaluation of these assets and properties and preparation of this report for Camflo International Inc., dated November 19, 2003 and the parameters and conditions employed in this evaluation were examined by me and adopted as representative and appropriate in establishing the value of these oil and gas properties according to the information available to date.
6.
THAT I have not, nor do I expect to receive, any direct or indirect interest in the properties or securities of Camflo International Inc., its participants or any affiliate thereof.
7.
THAT I have not examined all of the documents pertaining to the ownership and agreements referred to in this report, or the chain of Title for the oil and gas properties discussed.
8.
A personal field examination of these properties was considered to be unnecessary because the data available from the Company's records and public sources was satisfactory for our purposes.
C. W. Chapman, P.Eng.
President
CERTIFICATE OF QUALIFICATION
I, J. S. DECK, C.E.T., of the City of Calgary, Alberta, hereby certify:
1.
THAT I am registered as a Certified Engineering Technologist in the Province of Alberta, and I reside at 67 Edgehill Crescent N.W., Calgary, Alberta.
2.
THAT I have been employed in the petroleum industry since 1971 by various companies and have been directly involved in reservoir engineering, petrophysics, operations, and evaluations during that time.
3.
THAT I participated directly in the evaluation of these assets and properties and preparation of this report for Camflo International Inc., dated November 19, 2003 and the parameters and conditions employed in this evaluation were examined by me and adopted as representative and appropriate in establishing the value of these oil and gas properties according to the information available to date.
4.
THAT I have not, nor do I expect to receive, any direct or indirect interest in the properties or securities of Camflo International Inc., its participants or any affiliate thereof.
5.
THAT I have not examined all of the documents pertaining to the ownership and agreements referred to in this report, or the chain of Title for the oil and gas properties discussed.
6.
A personal field examination of these properties was considered to be unnecessary because the data available from the Company's records and public sources was satisfactory for our purposes.
J.S. Deck, C.E.T.
Associate
RESERVE AND ECONOMIC EVALUATION
GAS PROPERTIES
Owned by
CAMFLO INTERNATIONAL INC.
November 1, 2003
TABLE OF CONTENTS
Scope of Report
Authorization
Purpose
Reserve Definitions
Product Prices
Royalties
Capital Expenditures and Operating Costs
Economics
Constant Price Parameters
Executive Summary
Summary of Reserves and Economics
Discussion
Jurisdictional Map
ALBERTA
Prairie River
Snipe Lake
Glossary
SCOPE OF REPORT
Authorization
This evaluation has been authorized by Mr. Allan Crawford, on behalf of Camflo International Inc. The engineering analysis has been performed over the month of November 2003.
Purpose
The purpose of this report was to prepare a third party independent appraisal of the oil and gas reserves owned by Camflo International Inc. for the Company's financial reporting.
The values in this report do not include the value of the Company's undeveloped land holdings nor the tangible value of their interest in associated plant and well site facilities they may own. The cash flow forecasts include well and/or facility abandonment and reclamation costs and the offsetting salvage value of the tangible equipment after abandonment.
Reserve Definitions
The following definitions, extracted from the Canadian Oil and Gas Evaluation Handbook (COGEH) published by the Petroleum Society of CIM and the Calgary Chapter of the Society of Petroleum Evaluation Engineers (SPEE) as specified by NI 51-101 have been used in preparing this report.
5.4
Definitions of Reserves
The following definitions and guidelines have been prepared by the Standing Committee on Reserves Definitions of the CIM (Petroleum Society) after many years of consultations and deliberations. These definitions and guidelines must be used by qualified evaluators when evaluating and reporting oil and gas reserves and related substances.
The definitions and guidelines are designed to assist
·
Evaluators in making reserves estimates on a reasonably consistent basis;
·
Users of evaluation reports in understanding what such reports contain and, if necessary, in judging whether evaluators have followed generally accepted standards
The guidelines outline
·
General criteria for classifying reserves,
·
Procedures and methods for estimating reserves,
·
Confidence levels of individual entity and aggregate reserves estimates,
·
Verification and testing of reserves estimates.
The determination of oil and gas reserves involves the preparation of estimates that have an inherent degree of associated uncertainty. Categories of proved, probable and possible reserves have been established to reflect the level of these uncertainties and to provide an indication of the probability of recovery.
The estimation and classification of reserves requires the application of professional judgement combined with geological and engineering knowledge to assess whether or not specific reserves classification criteria have been satisfied. Knowledge of concepts including uncertainty and risk, probability and statistics, and deterministic and probabilistic estimation methods is required to properly use and apply reserves definitions. The concepts are presented and discussed in great detail within the guidelines of Section 5.5.
The following definitions apply to both estimates of individual Reserves Entities and the aggregate of reserves for multiple entities.
5.4.1
Reserves Categories
Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on
·
Analysis of drilling, geological, geophysical, and engineering data;
·
The use of established technology
·
Specified economic conditions, which are generally accepted as being reasonable,
and shall be disclosed.
Reserves are classified according to the degree of certainty associated with the estimates.
a.
Proved Reserves
Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
b.
Probable Reserves
Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved + probable reserves.
c.
Possible Reserves
Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved + probable + possible reserves.
Other criteria that must also be met for the categorization of reserves are provided in Section 5.3.2.
5.4.2
Development and Production Status
Each of the reserves categories (proved, probable and possible) may be divided into developed and undeveloped categories.
a.
Developed Reserves
Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g., when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.
Developed Producing Reserves
Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
Developed Non-Producing Reserves
Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.
b.
Undeveloped Reserves
Undeveloped reserves are those reserves expected to be recovered from know accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned.
In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to sub-divide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.
5.4.3
Levels of Certainty for Reported Reserves
The qualitative certainty levels contained in the definitions in Section 5.4.1 are applicable to individual Reserves Entities, which refers to the lowest level at which reserve calculations are performed, and to Reported Reserves, which refers to the highest level sum of individual entity estimates for which reserves estimates are presented. Reported Reserves should target the following levels of certainty under a specific set of economic conditions.
·
At least a 90 percent probability that the quantities actually recovered will equal or
exceed the estimated proved reserves;
·
At least a 50 percent probability that the quantities actually recovered will equal or
exceed the sum of the estimated proved + probable reserves;
·
At least a 10 percent probability that the quantities actually recovered will equal or
exceed the sum of the estimated proved + probable + possible reserves.
Product Prices
Chapman Petroleum Engineering Ltd. conducts continual surveillance and monitoring on a number of Benchmark product prices both locally and internationally. Based on historical data, current conditions and our view of the relevant political and economic trends, we independently prepare oil, gas and by-product price forecasts including predictions for the near term (first few years) with escalation thereafter for a maximum of 15 years, after which prices are held constant.
In establishing our forecasts we also consider input from operating companies, consulting firms, oil & gas marketing companies and financial institutions. Our forecasts are updated quarterly and the most current one utilized for this report is presented in Table 5 in the Executive Summary.
The Benchmark Oil Par Price shown is the equivalent price of light sweet crude landed in Edmonton to that of the West Texas Intermediate crude (WTI) in Cushing, Oklahoma after adjustments for transportation and the prevailing dollar exchange rate ($US/$Can).
The gas price forecast has been generated for this report to reflect the average Gas Reference Price (GRP) which is the price on which Crown royalty calculations are based.
The gas prices under various types of contracts currently available, i.e. conventional, local discount and export contracts, have been predicted to follow the same trends. The initial oil and gas prices for each property have been adjusted in this report to reflect the relative actual prices being received.
The Natural Gas Liquid (NGL) blended mix price has been established for each applicable property in this report based on the price and relative volumes of each NGL component of the gas stream recovered at the plant and wellhead for that property based on available plant and revenue data. For properties where actual data is not available, an average blended mix price has been estimated based on a typical liquid composition assumed to be 40% propane, 30% butane and 30% pentanes plus.
Any prices quoted in the property discussions reflect fully adjusted prices for crude quality, transportation, gas heating value and specific contractual arrangements. In the case of delayed production the equivalent 2003 price for that production has been quoted.
Royalties
A full provision for Crown royalties and mineral taxes, freehold and overriding royalties and the latest royalty and incentive regulations of the applicable Provincial Government have been included in this report.
Crown royalties for oil have been categorized as per the latest regulations as Old Crown Royalty (OC), New Light Crude Crown Royalty (NLC), New Heavy Crude Crown Royalty (NHC) and Third Tier Crown Royalty (3TC).
The Alberta Royalty Tax Credit (ARTC) is generally included on a corporate level only as prescribed by the policy, for only those properties which qualify. Production which has been acquired from an operator who fully utilized its ARTC does not qualify for ARTC for the purchaser.
Companies which are below their maximum limits might apply the ARTC to individual properties for disposition purposes etc. In these cases, upon request we would generate the ARTC for individual properties.
The forecast Alberta Royalty Tax Credit (ARTC) rate and maximum reimbursement, presented on Attachment 1, has been prepared based on the Government of Alberta Information Letter, 95-9 dated February 15, 1995, effective January 1, 1995. The ARTC is based on a formula keyed to the average "Par Price" for Alberta crude, and the Alberta "Gas Reference Price". The ARTC rate refers to the percentage of royalty payments to be reimbursed. This rate is also utilized in determining the maximum annual reimbursement to be made to each Company as a percentage of the reference maximum.
In accordance with the policy the Provincial Government announced in 1998 that it was considering changes to the ARTC to be introduced, at the earliest, at January 1, 2001. The Government staff has recently indicated to us that a number of changes were proposed but only two passed first reading. These proposed changes have been revoked and the policy will be continued as before still with a three-year rolling term. It is evident that the Provincial Government is in favor of continuing the incentive for small explorers. Given that there was an opportunity to make changes and no changes were made, it is our position that the existing policy will be maintained, indefinitely.
Capital Expenditures and Operating Costs
Operating costs and capital expenditures have been based on historical experience and analogy where necessary and have been escalated as follows:
2003
- No Escalation
2004-2018
- 1.5% per year
Thereafter
- No Escalation
Economics
The results of the economic analysis presented in this report are in a condensed form presented on one page for simplicity in analyzing the cash flows, however, if for any reason more extensive breakdown of the cash flow is required, a separate schedule can be provided showing the full derivation and breakdown of any or all of the columns on the summary page.
The economic presentation shows the gross property and company gross and net (before and after royalty) production of oil gas and each NGL product along with the product prices adjusted for oil quality and heating value of gas. Oil prices also include the deduction for trucking costs where applicable for royalty deductions.
The second level includes the revenues, royalties, operating costs, processing income, capital and cash flow of the property. Royalty values shown here are after the reimbursement to the Company of the Gas Cost Allowance (GCA). Operating costs are presented for the gross property and the company share, split between variable and fixed costs, and the effective cost per BOE.
Net revenues are presented annually and as a net back $/BOE. Revenue from custom processing of oil or gas is presented separately.
The third level of data presents the cumulative cash flow values (present worth) for various discount rates. Also, the net cash flow breakdown is presented. The project profitability criteria are summarized on the bottom right of the page. These data are not relevant in the case of corporate evaluations but are useful in assessing individual capital projects.
The Alberta Royalty Tax Credit is not included on this one page presentation for individual files or corporate consolidations. These values are presented on a separate page in the corporate consolidations for each reserve category.
Constant Price Parameters
For the Constant Price we have utilized the October 31, 2003 posted prices for oil and gas and have held them constant throughout as shown in Table 5 of the Executive Summary.
Adjustments for crude quality, gas heating value and NGL trucking and fractionation have still been applied to the average prices to reflect actual prices being received. In addition, no escalation has been applied to either the capital expenditures or operating costs.
It has been assumed that the existing ARTC program will continue indefinitely. At these prices, the ARTC benefits are already at the minimum under the policy.
In the Constant Price cash flows the magnitude of the gross and net reserves will not change except where production forecasts have been truncated or extended due to economic limits being reached earlier or later in the life of the properties than in the forecast price case, and due to the impact of royalties which are price related.
The average price shown in the cash flows may differ from year to year due to variations in the proportionate production volumes from each property relative to the total.
EXECUTIVE SUMMARY
INDEX
Forecast Prices and Costs
Table 1:
Summary of Oil & Gas Reserves
Table 2:
Summary of Net Present Values
Table 3:
Total Future Net Revenue (Undiscounted)
Table 4:
Future Net Revenue – By Production Group
Table 4a:
Reserves and Net Present Values – By Production Group
Table 5:
Constant Prices and Prices Forecast
Constant Prices and Costs
Table 6:
Summary of Oil & Gas Reserves
Table 7:
Summary of Net Present Values
Table 8:
Total Future Net Revenue (Undiscounted)
Table 9:
Future Net Revenue – By Production Group
Table 9a:
Reserves and Net Present Values – By Production Group
PRAIRIE RIVER, ALBERTA
INDEX
Discussion
Ownership
Reserves
Production
Product Prices
Capital Expenditures
Operating Costs
Economics
Attachments
Figure 1:
Land and Well Map
Table 1:
Schedule of Lands, Interests and Royalty Burdens
Table 2:
Summary of Reserves
Summary of Reserves and Reservoir Parameters
Proved Developed Producing
a)
Well 15-16-69-16 W5M, Gething
Table 3:
Summary of Anticipated Capital Expenditures.
Table 4:
Economic Summary
Individual Cash Flows
Proved Developed Producing
a)
Well 15-16-69-16 W5M, Gething
PRAIRIE RIVER, ALBAERTA
DISCUSSION
Ownership
The Company owns a 21.6 percent working interest in 640 acres of land in this area, which contains one producing gas well, as shown on the map, Figure 1. The Company also owns an option on 1,920 acres of land in this area but must first drill an additional well before these lands can be earned. Production is subject to new Crown royalties.
A detailed description of the lands, interests and royalty burdens is presented in Table 1.
Reserves
Proved developed producing marketable gas reserves of 1,611 MMscf have been estimated for the well 15-16-69-16 W5M based on reservoir parameters determined from an analysis of the well logs, a production test and production.
A summary of reserves is presented in Table 2 and a summary of the reserves and reservoir parameters are presented in Table 2a.
Production
Gas production from this area commenced during October and is currently estimated to be 800 Mscf/d. This rate is expected to begin a gradual decline to an eventual economic limit, almost immediately.
Product Prices
An average 2003 gas sales price of $6.25 per Mscf and has been estimated for this area.
Capital Expenditures
Gross capital expenditures of $29,000 ($6,000 net to the Company) have been estimated for this area as presented in Table 3.
Operating Costs
Operating costs of $3,000 per well per month plus gas processing costs of $0.66 per Mscf have been estimated for this area.
Economics
A summary of the economics is presented in Table 4 and the results of the economic analysis performed on this property are presented Table 4a.
SNIPE LAKE, ALBERTA
INDEX
Discussion
Ownership
Reserves
Production
Product Prices
Capital Expenditures
Operating Costs
Economics
Attachments
Figure 1:
Land and Well Map
Table 1:
Schedule of Lands, Interests and Royalty Burdens
Table 2:
Summary of Reserves
Summary of Reserves and Reservoir Parameters
Proved Developed Non-Producing
a)
Well 3-28-69-17 W5M, Falher
b)
Well 3-28-69-17 W5M, Gething
Table 3:
Summary of Anticipated Capital Expenditures.
Table 4:
Economic Summary
Consolidated Cash Flows
a)
Total Proved Developed Non-Producing
Individual Cash Flows
Proved Developed Non-Producing
b)
Well 3-28-69-17 W5M, Falher
c)
Well 3-28-69-17 W5M, Gething
SNIPE LAKE, ALBERTA
DISCUSSION
Ownership
The Company owns various working interests in 8,960 acres of land in this area, which contains one shut-in dually completed gas well, as shown on the map, Figure 1. Production is subject to new Crown and some overriding royalties.
A detailed description of the lands, interests and royalty burdens is presented in Table 1.
Reserves
Proved developed producing marketable gas reserves of 4,387 MMscf have been estimated for the Falher and Gething zones in the well 3-28-69-17 W5M based on reservoir parameters determined from an analysis of the well logs and production testing.
A summary of reserves is presented in Table 2 and a summary of the reserves and reservoir parameters are presented in Tables 2a and 2b
Production
Gas production from this area is estimated to commence at a rate of 1,500 Mscf/d for the Falher zone and 3,500 Mscf/d for the Gething zone in March 2004. These rates are expected to begin a gradual decline to an eventual economic limit almost immediately. The well has recently been flow tested from both zones. These tests confirm the initial rates used.
Product Prices
An average 2004 gas sales price of $5.50 per Mscf and has been estimated for this area.
Capital Expenditures
Gross capital expenditures of $1,639,000 ($162,000 net to the Company) have been estimated for this area as presented in Table 3.
Operating Costs
Operating costs of $2,000 per zone per well per month plus gas processing costs of $0.66 per Mscf have been estimated for this area.
Economics
A summary of the economics is presented in Table 4 and the results of the economic analysis performed on this property are presented Table 4a through 4c.
PLEASE CONTACT THE COMPANY AT CAMFLO@TELUS.NET FOR FULL ECONOMIC TABLES
