EX-99.1 2 ex991.htm ANNUAL INFORMATION FORM FOR THE YEAR ENDED DECEMBER 31, 2006 Annual Information Form for the year ended December 31, 2006
Exhibit 99.1
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
ANNUAL INFORMATION FORM
 
For the year ended December 31, 2006
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
March 12, 2007
 
 
 
 
 
 
 
 
 



TABLE OF CONTENTS
 
    Page
GLOSSARY OF TERMS   iii
ABBREVIATIONS AND CONVERSIONS   v
PRESENTATION OF ENERPLUS' OIL AND GAS RESERVES, RESOURCES AND PRODUCTION INFORMATION   vi
PRESENTATION OF ENERPLUS' FINANCIAL INFORMATION   x
FORWARD-LOOKING STATEMENTS AND INFORMATION   x
STRUCTURE OF ENERPLUS RESOURCES FUND   1
GENERAL DEVELOPMENT OF ENERPLUS RESOURCES FUND   3
  Historical Overview   3
  Developments in the Past Three Years   3
  Events Subsequent to 2006 Year-End   5
OIL AND NATURAL GAS RESERVES   6
  Overview of Reserves   6
  Summary of Aggregate Enerplus Reserves   7
  Summary of Conventional Oil and Natural Gas Reserves   9
  Summary of Joslyn Project Bitumen Reserves   18
  Reconciliation of Reserves   21
  Reconciliation of Changes in Net Present Value of Future Net Revenue   25
  Undeveloped Reserves   26
  Proved and Probable Reserves Not on Production   27
OPERATIONAL INFORMATION   27
  Overview   27
  Description of Principal Properties and Operations   27
  Summary of Principal Production Locations   37
  Oil and Natural Gas Wells and Unproved Properties   38
  Exploration and Development Activities   38
  Quarterly Production History   39
  Quarterly Netback History   40
  Abandonment and Reclamation Costs   42
  Tax Horizon   42
  Costs Incurred   42
  Marketing Arrangements and Forward Contracts   43
  Environment, Health and Safety   43
  Impact of Environmental Protection Requirements   45
  Additional Operational Information   45
INFORMATION RESPECTING ENERPLUS RESOURCES FUND   46
  Description of the Trust Units and the Trust Indenture   46
  Description of the Royalty Agreements and EnerMark's Subordinated Notes   52
  Management and Corporate Governance   54
  Unitholder Rights Plan   54
DEBT OF ENERPLUS   55
  Bank Credit Facility   55
  Senior Unsecured Notes   56
DISTRIBUTIONS TO UNITHOLDERS   57
  Cash Distributions   57
  Distribution History   58
  Canadian Tax Reporting Matters   58
  U.S. Tax Reporting Matters   58
INDUSTRY CONDITIONS   59
RISK FACTORS   63
MARKET FOR SECURITIES   77
DIRECTORS AND OFFICERS   78
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS   81
MATERIAL CONTRACTS AND DOCUMENTS AFFECTING THE RIGHTS OF SECURITYHOLDERS   81
INTERESTS OF EXPERTS   82
REGISTRAR AND TRANSFER AGENT   82
ADDITIONAL INFORMATION   82
APPENDIX "A" — REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR   A-1
APPENDIX "B" — REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR   B-1
APPENDIX "C" — REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR   C-1
APPENDIX "D" — REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION   D-1
APPENDIX "E" — AUDIT & RISK MANAGEMENT COMMITTEE DISCLOSURE   E-1
APPENDIX "F" — SFAS NO. 69 SUPPLEMENTAL RESERVE INFORMATION   F-1



GLOSSARY OF TERMS
 
        Unless the context otherwise requires, in this Annual Information Form, the following terms and abbreviations have the meanings set forth below. Additional terms relating to oil and natural gas reserves, resources and operations have the meanings set forth under "Presentation of Enerplus' Oil and Gas Reserves, Resources and Production Information".
 
"AECO" means the physical storage and trading hub for natural gas on the TransCanada Alberta Transmission System (NOVA) which is the delivery point for the various benchmark Alberta index prices;
 
"bitumen" means a highly viscous crude oil which is too thick to flow in its native state and which cannot be produced without altering its viscosity. The density of bitumen is generally less than 10o API;
 
"D&M" means DeGolyer and MacNaughton, independent petroleum consultants;
 
"D&M Report" means the independent engineering evaluation of Enerplus' U.S. conventional oil, NGLS and natural gas interests prepared by D&M dated February 1, 2007 and effective December 31, 2006, utilizing commodity price forecasts of Sproule (for internal consistency in Enerplus' reserves reporting) dated December 31, 2006;
 
"ECT" means Enerplus Commercial Trust, a trust organized under the laws of Alberta (the trustee of which is Enerplus ECT Resources Ltd., an Alberta corporation) and an indirect wholly owned subsidiary of the Fund;
 
"EGEM" means Enerplus Global Energy Management Company, an indirect wholly owned subsidiary of the Fund which, prior to its acquisition by Enerplus from a third party, provided management and administrative services to Enerplus;
 
"EnerMark" means EnerMark Inc., a corporation organized under the Business Corporations Act (Alberta) and an indirect wholly owned subsidiary of the Fund;
 
"Enerplus" means Enerplus Resources Fund and its subsidiaries, taken as a whole;
 
"Enerplus Oil & Gas" means Enerplus Oil & Gas Ltd., a corporation organized under the Business Corporations Act (Alberta) and an indirect wholly owned subsidiary of the Fund;
 
"Enerplus USA" means Enerplus Resources (USA) Corporation, a corporation organized under the laws of Delaware and an indirect wholly owned subsidiary of EnerMark;
 
"ERC" means Enerplus Resources Corporation, a corporation organized under the Business Corporations Act (Alberta) and an indirect wholly owned subsidiary of the Fund;
 
"Fund" means Enerplus Resources Fund;
 
"GAAP" means generally accepted accounting principles;
 
"GLJ" means GLJ Petroleum Consultants Ltd., independent petroleum consultants;
 
"GLJ Joslyn Resources Report" means the independent engineering evaluation of the contingent resources attributable to Enerplus' interest in the Joslyn Project prepared by GLJ dated February 2, 2007 and effective December 31, 2006;
 
"GLJ Reserves Report" means the independent engineering evaluation of the reserves attributable to Enerplus' interest in the Joslyn Project prepared by GLJ dated January 29, 2007 and effective December 31, 2006, utilizing commodity price forecasts of Sproule (for internal consistency in Enerplus' reserves reporting) dated December 31, 2006;
 
"Henry Hub" means the physical storage and trading hub in Louisiana which is the delivery point for the NYMEX natural gas contract;
 
"Income Trust Tax Proposals" has the meaning ascribed thereto under "General Development of the Fund — Developments in the Past Three Years — Federal Government Pronouncements on Income Trusts";
 
"Joslyn Bitumen" means the bitumen produced from the Joslyn Project;
 
 
 
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"Joslyn Project" or the "Project" means the development of Oil Sands Lease #24 located in the Athabasca oil sands fairway of northeastern Alberta;
 
"Joslyn Lease" means the sections of land contained within Alberta Oil Sands Lease No. 7280060T24 and Alberta Oil Sands Permit No. 7099110070;
 
"NI 51-101" means National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities, adopted by the Canadian securities regulatory authorities;
 
"North Mine" means the northern portion of the Joslyn Lease, currently designated as a mineable portion of the Joslyn Project;
 
"NYMEX" means the New York Mercantile Exchange;
 
"NYSE" means the New York Stock Exchange;
 
"Operating Subsidiaries" means the direct and indirect subsidiaries of the Fund that own, acquire and operate oil and natural gas assets for the benefit of the Fund (with the material Operating Subsidiaries being EnerMark, ERC, Enerplus Oil & Gas, ECT and Enerplus USA);
 
"SAGD" means Steam Assisted Gravity Drainage, an in situ production process used to recover bitumen from oil sands;
 
"SEC" means the United States Securities and Exchange Commission;
 
"Sproule" means Sproule Associates Limited, independent petroleum consultants;
 
"South Mine" means the southern portion of the Joslyn Lease on which potential future bitumen resources have been identified;
 
"Sproule Report" means the independent engineering evaluation of Enerplus' Canadian conventional oil, NGLs and natural gas interests prepared by Sproule dated February 14, 2007 and effective December 31, 2006, utilizing commodity price forecasts of Sproule dated December 31, 2006;
 
"subsidiary" has the meaning assigned thereto in the Securities Act (Alberta);
 
"Tax Act" means the Income Tax Act (Canada);
 
"Total" means Total E&P Canada Ltd., a wholly owned subsidiary of Total S.A., which (through its subsidiary, Deer Creek Energy Limited) is the operator of the Joslyn Project;
 
"Trust Indenture" means the Amended and Restated Trust Indenture dated January 1, 2004 among EnerMark, ERC and the Trustee, as may be amended, supplemented or restated from time to time;
 
"Trust Units" means the trust units of the Fund, each representing an equal undivided beneficial interest in the Fund;
 
"Trustee" means CIBC Mellon Trust Company, or its successor as trustee of the Fund;
 
"TSX" means the Toronto Stock Exchange; and
 
"WTI" means West Texas Intermediate crude oil that serves as the benchmark crude oil for the NYMEX crude oil contract delivered in Cushing, Oklahoma.
 
 
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ABBREVIATIONS AND CONVERSIONS
 
        In this Annual Information Form, the following abbreviations have the meanings set forth below.
 
API   American Petroleum Institute
bbls   barrels, with each barrel representing 34.972 imperial gallons or 42 U.S. gallons
bbls/d   barrels per day
Bcf   billion cubic feet
Bcf/d   billion cubic feet per day
BOE(1)   barrels of oil equivalent converting 6 Mcf of natural gas to one barrel of oil equivalent and one barrel of natural gas liquids to one barrel of oil equivalent.
BOE/d   barrels of oil equivalent per day
Mbbls   one thousand barrels
MBOE   one thousand barrels of oil equivalent
Mcf   one thousand cubic feet
Mcf/d   one thousand cubic feet per day
MMbbls   one million barrels
MMBOE   one million barrels of oil equivalent
mmbtu   one million British Thermal Units
MMcf   one million cubic feet
MMcf/d   one million cubic feet per day
NGLs   natural gas liquids
 
Note:
(1)    A BOE conversion ratio of 6 Mcf:1 BOE is based on an energy equivalency conversion method primarily at the burner tip and does not represent a value equivalency at the wellhead.
 
        In this Annual Information Form, unless otherwise indicated, all dollar amounts are in Canadian dollars and all references to "$" are to Canadian dollars.
 
        The following table sets forth certain standard conversions between Standard Imperial Units and the International System of Units (or metric units).
 
To Convert From   To   Multiply By
Mcf   cubic metres   28.174
cubic metres   cubic feet   35.494
bbls   cubic metres   0.159
cubic metres   bbls   6.293
feet   metres   0.305
metres   feet   3.281
miles   kilometres   1.609
kilometres   miles   0.621
acres   hectares   0.4047
hectares   acres   2.471
 
 
 
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PRESENTATION OF ENERPLUS'
OIL AND GAS RESERVES, RESOURCES AND PRODUCTION INFORMATION
 
Note to Reader Regarding Oil and Gas Information, Definitions and National Instrument 51-101
 
        The oil and gas operational and reserves information contained in this Annual Information Form contains the information required to be included in the Statement of Reserves Data and Other Oil and Gas Information pursuant to NI 51-101 adopted by the Canadian securities regulatory authorities and has been prepared and prescribed in accordance with Form 51-101F1. Readers should also refer to the Report on Reserves Data by Sproule attached hereto as Appendix "A", the Report on Reserves Data by GLJ attached hereto as Appendix "B", the Report on Reserves Data by D&M attached as Appendix "C" and the Report of Management and Directors on Oil and Gas Disclosure attached hereto as Appendix "D". The effective date for the Statement of Reserves Data and Other Oil and Gas Information contained in this Annual Information Form is December 31, 2006 and the information contained in the Annual Information Form has been prepared as of March 12, 2007.
 
        Certain of the following definitions and guidelines are contained in Section 5.4 of Volume 1 of the Canadian Oil and Gas Evaluation Handbook (First Edition, June 30, 2002) (the "COGE Handbook") prepared jointly by The Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society) (the "CIM (Petroleum Society)") and have been prepared by the Standing Committee on Reserves Definitions of the CIM (Petroleum Society). Readers should consult the COGE Handbook for additional explanation and guidance. Certain other terms used in this Annual Information Form have the meanings assigned to them in NI 51-101 and accompanying Companion Policy 51-101CP, adopted by the Canadian securities regulatory authorities.
 
Disclosure of Reserves and Production Information
 
        In this Annual Information Form, all estimates of oil and natural gas reserves and production are presented on a "company interest" basis (as defined below), unless expressly indicated that they have been presented on a "gross" or "net" basis. "Company interest" is not a term defined or recognized under NI 51-101 and does not have a standardized meaning under NI 51-101. Therefore, the "company interest" reserves of Enerplus may not be comparable to similar measures presented by other issuers, and investors are cautioned that "company interest" reserves should not be construed as an alternative to "gross" or "net" reserves calculated in accordance with NI 51-101.
 
        Enerplus' actual oil and natural gas reserves and future production may be greater than or less than the estimates provided in this Annual Information Form. The estimated future net revenue from the production of Enerplus' oil and natural gas reserves does not represent the fair market value of Enerplus' reserves. Furthermore, the estimates of future net revenue attributable to Enerplus' reserves in this Annual Information Form do not give effect to the Income Trust Tax Proposals: see "Oil and Natural Gas Reserves — Overview of Reserves" for additional information.
 
        The United States Securities and Exchange Commission (the "SEC") generally permits oil and gas issuers, in their filings with the SEC, to disclose only proved reserves net of royalties and interests of others that an issuer has demonstrated with reasonable certainty by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. Canadian securities laws permit oil and gas issuers, in their filings with Canadian securities regulators, to disclose not only Proved Reserves but also Probable Reserves (each as defined in NI 51-101 and described below), and to disclose reserves and production on a "gross" basis before deducting royalties and similar payments, as well as on a "net" basis. Probable Reserves are higher risk and are generally believed to be less likely to be accurately estimated or recovered than Proved Reserves. Enerplus has prepared this Annual Information Form in accordance with Canadian disclosure requirements, and as a result, Enerplus has disclosed reserves designated as "Probable Reserves" and "Proved plus Probable Reserves". The SEC's guidelines strictly prohibit reserves in these categories from being included in filings with the SEC that are required to be prepared in accordance with U.S. disclosure requirements. Moreover, Enerplus has determined and disclosed estimated future net revenue from its reserves using both constant and forecast prices and costs, whereas the SEC generally requires that prices and costs be held constant at levels in effect at the date of the reserve report. As a consequence, Enerplus'
 
 
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production volumes and reserve estimates may not be comparable to those made by companies utilizing United States disclosure standards. Furthermore, Enerplus has disclosed certain "contingent resources". For a description of the definition of, and the risks and uncertainties surrounding the disclosure of, contingent resources, see "— Disclosure of Contingent Resources for the Joslyn Project" below.
 
        Notwithstanding the above, Enerplus has included as Appendix "F" to this Annual Information Form certain disclosure relating to Enerplus' oil and gas reserves and operations in accordance with U.S. Financial Accounting Standards Board's Statement No. 69 — Disclosures About Oil and Gas Producing Activities, which complies with the SEC's guidelines regarding disclosure of oil and gas reserves.
 
        Enerplus has adopted the standard of 6 Mcf:1 BOE when converting natural gas to BOEs. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 BOE is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
 
Disclosure of Contingent Resources for the Joslyn Project
 
        In this Annual Information Form, Enerplus has disclosed estimated volumes of "contingent resources" that have been prepared by GLJ pursuant to the GLJ Joslyn Resources Report and which relate to certain potential mineable portions of the Joslyn Lease. "Resources" are oil and gas volumes that are estimated to have originally existed in the earth's crust as naturally occurring accumulations but are not capable of being classified as "reserves" as described below. "Contingent resources" is a recognized category of resources in the COGE Handbook and is defined as "those quantities of oil and gas estimated on a given date to be potentially recoverable from known accumulations but are not currently economic". However, as indicated in the COGE Handbook, criteria other than economics may cause a quantity to be classified as a resource rather than a reserve. Section 5 of Volume 2 of the COGE Handbook states that the following issues are contingencies that affect the classification as resources rather than reserves: ownership considerations; drilling requirements; testing requirements; regulatory considerations; infrastructure and market considerations; timing of production and development; and economic requirements. Contingent resources may also include those quantities of hydrocarbons that are estimated to be potentially recoverable using technology that is under development. Resources and contingent resources do not constitute, and should not be confused with, reserves. See "Risk Factors — Risks Related to Enerplus' Business and Operations — Enerplus' actual reserves and resources will vary from its reserve and resource estimates, and those variations could be material."
 
        There is no certainty that Enerplus will produce any portion of the volumes currently classified as "contingent resources". The primary contingencies which currently prevent the classification of Enerplus' disclosed contingent resources associated with the Joslyn Project as "reserves" consist of current uncertainties around the specific scope of the Joslyn Project (and in particular the finalization of an overall lease development plan), timing of the proposed development as it relates to proposed changes in the lease development plan, proposed reliance on technologies that have not yet been demonstrated to be commercially applicable in oil sands applications, the uncertainty regarding marketing plans for production from the subject areas and improved estimation of project costs. Enerplus believes that development of the Joslyn Project will proceed, including the development of the contingent resources associated with the North Mine and South Mine as disclosed in this Annual Information Form. However, there are a number of inherent risks and contingencies associated with such development, including commodity price fluctuations, project costs and those other risks and contingencies described above and under "Risk Factors" in this Annual Information Form and particularly under "Risk Factors — Risks Related to Enerplus' Business and Operations — The Joslyn Project is in the early development stage and is subject to numerous risks."
 
Interests in Reserves, Production, Wells and Properties
 
        In addition to the terms having defined meanings set forth in NI 51-101, the terms set forth below have the following meanings when used in this Annual Information Form:
 
        "company interest" means, in relation to Enerplus' interest in production or reserves, its working interest (operating or non-operating) share before deduction of royalties and including any royalty interests of Enerplus. See "— Disclosure of Reserves and Production Information" above.
 
 
vii


        "gross" means:
 
(i)  in relation to Enerplus' interest in production or reserves, its working interest (operating or non-operating) share after deduction of royalty obligations, plus Enerplus' royalty interests in production or reserves;
(ii)   in relation to wells, the total number of wells in which Enerplus has an interest; and 
(iii)  in relation to properties, the total area of properties in which Enerplus has an interest.
             
        "net" means:
 
(i) in relation to Enerplus' interest in production or reserves, its working interest (operating or non-operating) share after deduction of royalty obligations, plus Enerplus' royalty interests in production or reserves;
(ii)  in relation to Enerplus' interest in wells, the number of wells obtained by aggregating Enerplus' working interest in each of its gross wells; and
(iii)  in relation to Enerplus' interest in a property, the total area in which Enerplus has an interest multiplied by the working interest owned by Enerplus.
 
        "working interest" means the percentage of undivided interest held by Enerplus in the oil and/or natural gas or mineral lease granted by the mineral owner, Crown or freehold, which interest gives Enerplus the right to "work" the property (lease) to explore for, develop, produce and market the leased substances.
 
Reserves Categories and Levels of Certainty for Reported Reserves
 
        "Reserves" are those remaining quantities of oil and gas anticipated to be economically recoverable from known accumulations. Reserves may be divided into proved and probable categories (as well as possible reserves, which Enerplus does not report).
 
        "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.
 
        "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 plus Probable Reserves.
 
        The qualitative certainty levels referred to in the definitions above are applicable to individual reserves entities (which refers to the lowest level at which reserves 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; and
        •    at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated Proved plus Probable Reserves.
Development and Production Status
 
        Each of the reserves categories reported by Enerplus (Proved and Probable) may be divided into developed and undeveloped categories:
 
        "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 (for example, 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" 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 
        
 
viii

 
              must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
 
        •    "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.
 
        "Undeveloped Reserves" are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, 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 or Probable) to which they are assigned.
 
Description of Price and Cost Assumptions
 
       "Constant prices and costs" means, unless expressly noted otherwise, prices and costs used in an estimate that are:
         (i)   Enerplus' prices and costs as at December 31, 2006, held constant throughout the estimated lives of the properties to which the estimate applies; and
 
        "Forecast prices and costs" means future prices and costs that are:
 
        (i)    generally accepted as being a reasonable outlook of the future; and
 
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PRESENTATION OF ENERPLUS' FINANCIAL INFORMATION
 
        The financial information included and incorporated by reference in this Annual Information Form has been prepared in accordance with Canadian GAAP. Canadian GAAP differs in some significant respects from U.S. GAAP and therefore this financial information may not be comparable to the financial information of U.S. companies. The principal differences as they apply to the Fund are summarized in Note 14 to the Fund's audited consolidated financial statements for the year ended December 31, 2006, which are available on the Fund's SEDAR profile at www.sedar.com, on EDGAR at www.sec.gov as part of the Form 6-K filed with the SEC on February 23, 2007, and on Enerplus' website at www.enerplus.com.
 
        In this Annual Information Form, unless otherwise indicated, all dollar amounts are in Canadian dollars and all references to "$" are to Canadian dollars.

FORWARD-LOOKING STATEMENTS AND INFORMATION
 
        This Annual Information Form contains certain forward-looking statements and forward-looking information which are based on Enerplus' current internal expectations, estimates, projections, assumptions and beliefs. The use of any of the words "anticipate", "continue", "estimate", "expect", "may", "will", "project", "plan", "should", "believe" and similar expressions are intended to identify forward-looking statements and forward-looking information. These statements are not guarantees of future performance and involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements or information. Enerplus believes the expectations reflected in those forward-looking statements and information are reasonable but no assurance can be given that these expectations will prove to be correct, and such forward-looking statements and information included in this Annual Information Form should not be unduly relied upon. Such forward-looking statements and information speak only as of the date of this Annual Information Form and Enerplus does not undertake any obligation to publicly update or revise any forward-looking statements or information, except as required by applicable laws.
 
        In particular, this Annual Information Form contains forward-looking statements and information pertaining to the following:
    •    the quantity of, and future net revenues from, Enerplus' reserves and/or resources; 
    •    crude oil, NGLs, natural gas and bitumen production levels; 
    •    commodity prices, foreign currency exchange rates and interest rates; 
    •    capital expenditure programs and other future expenditures; 
    •    supply and demand for oil, NGLs and natural gas; 
    •    expectations regarding Enerplus' ability to raise capital and to continually add to reserves and/or resources through acquisitions and development; 
    •    schedules for and timing of certain projects, including the Joslyn Project, and Enerplus' strategy for growth; 
    •    Enerplus' future operating and financial results; and 
    •    treatment under governmental and other regulatory regimes and tax, environmental and other laws.
        Enerplus' actual results could differ materially from those anticipated in these forward-looking statements and information as a result of both known and unknown risks, including the risk factors set forth under "Risk Factors" in this Annual Information Form and those set forth below:
 
 
volatility in market prices for oil, NGLs and natural gas; 
 
actions by governmental or regulatory authorities including changes in income tax laws (including those relating to mutual fund and income trusts or investment eligibility) or changes in tax laws and incentive programs relating to the oil and gas industry and income trusts;
 
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    •    changes or fluctuations in oil, NGLs, natural gas and bitumen production levels; 
    •    changes in foreign currency exchange rates and interest rates; 
    •    changes in capital and other expenditure requirements and debt service requirements; 
    •    liabilities and unexpected events inherent in oil and gas operations, including geological, technical, drilling and processing risks; 
    •    actions of industry partners; 
    •    uncertainties associated with estimating reserves and resources; 
    •    competition for, among other things, capital, acquisitions of reserves and resources, undeveloped lands and skilled personnel; 
    •    incorrect assessments of the value of acquisitions; 
    •    Enerplus' success at the acquisition, exploitation and development of reserves and resources; 
    •    changes in general economic, market and business conditions in Canada, North America and worldwide; and 
    •    changes in environmental or other legislation applicable to Enerplus' operations, and Enerplus' ability to comply with current and future environmental and other laws.
        Many of these risk factors and other specific risks and uncertainties are discussed in further detail throughout this Annual Information Form and in Enerplus' management's discussion and analysis for the year ended December 31, 2006, which is available through the internet on Enerplus' SEDAR profile at www.sedar.com, on EDGAR at www.sec.gov as part of the Form 6-K filed with the SEC on February 23, 2007, and on Enerplus' website at www.enerplus.com. Readers are also referred to the risk factors described in this Annual Information Form under "Risk Factors" and in other documents Enerplus files from time to time with securities regulatory authorities. Copies of these documents are available without charge from Enerplus or electronically on the internet on Enerplus' SEDAR profile at www.sedar.com, on EDGAR at www.sec.gov and on Enerplus' website at www.enerplus.com.
 
 
 
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ENERPLUS RESOURCES FUND

Annual Information Form
for the year ended December 31, 2006

STRUCTURE OF ENERPLUS RESOURCES FUND
Enerplus Resources Fund
 
        Enerplus Resources Fund is an energy trust created in 1986 under the laws of the Province of Alberta pursuant to the Trust Indenture. The Fund's assets currently consist of the securities of its directly and indirectly owned subsidiaries and 95%, 99% and 99% royalties on the crude oil and natural gas property interests of EnerMark, ERC and Enerplus Oil & Gas, respectively. The head, principal and registered office of Enerplus is located at The Dome Tower, 3000, 333 - 7th Avenue S.W., Calgary, Alberta, T2P 2Z1. Enerplus also has a U.S. office located at Wells Fargo Center, Suite 1300, 1700 Lincoln Street, Denver, Colorado, 80203. The Trustee of the Fund is CIBC Mellon Trust Company located at The Dome Tower, Suite 600, 333 - 7th Avenue S.W., Calgary, Alberta T2P 2Z1. The board of directors of EnerMark is responsible for the governance of Enerplus.
 
        The Fund's primary focus is to maximize value and cash distributions to its unitholders over the long-term from the net cash flow generated by the operation and development of its Operating Subsidiaries' existing crude oil and natural gas properties and other energy-related assets and the strategic acquisition and rationalization of properties and assets. See "Operational Information — Overview".
 
Operating Subsidiaries
 
        The Fund's Operating Subsidiaries acquire, exploit and operate crude oil and natural gas assets for the benefit of the Fund. See "Operational Information" and "Oil and Natural Gas Reserves" for information regarding the operations and oil and natural gas reserves and contingent bitumen resources of Enerplus. The Fund's material Operating Subsidiaries are EnerMark, ERC, Enerplus Oil & Gas, ECT and Enerplus USA.
 
        Each of EnerMark, ERC and Enerplus Oil & Gas are corporations organized under the Business Corporations Act (Alberta). ECT is a trust organized under the laws of Alberta and Enerplus USA is a corporation organized under the laws of Delaware. All of the issued and outstanding securities of each of EnerMark, ERC, Enerplus Oil & Gas, ECT and Enerplus USA are indirectly owned by the Fund.
 
 
 
1

 
 
Organization Chart
 
        The simplified organizational structure of Enerplus, including the material Operating Subsidiaries of the Fund and the flow of funds from those Operating Subsidiaries to the Fund and from the Fund to its unitholders, is set forth below:
 
 
 
 
2

 

GENERAL DEVELOPMENT OF ENERPLUS RESOURCES FUND
 
Historical Overview
 
        Enerplus Resources Fund was formed in 1986. The Fund's Trust Units are currently traded on the TSX under the symbol "ERF.UN" and on the NYSE under the symbol "ERF". The Fund was historically one of a group of royalty trusts, income funds and other entities managed by companies within the Enerplus organization.
 
Developments in the Past Three Years
 
Acquisition of Ice Energy Limited
 
        On January 7, 2004, Enerplus completed the acquisition of all of the issued and outstanding shares of Ice Energy Limited. Enerplus previously owned approximately 12.7% of the shares of Ice Energy Limited which were acquired in a prior transaction. Total consideration for all of the Ice Energy Limited shares, including those previously owned by Enerplus, was $121.2 million. Enerplus also assumed a working capital deficiency of $9.3 million. As a result of this acquisition, Enerplus acquired an interest in the Shackleton area of western Saskatchewan. The acquired interests also include a 50% working interest in a joint venture to develop a commercial coalbed methane (also known as natural gas from coal) project in central Alberta.
 
Acquisition of Properties from ChevronTexaco Corporation
 
        On June 30, 2004, Enerplus completed the acquisition of conventional oil and natural gas interests located in western Canada from ChevronTexaco Corporation for total consideration of approximately $467.2 million. The acquired production was weighted approximately 46% to natural gas and 54% to crude oil and NGLs and the acquisition also provided Enerplus with approximately 99,200 gross (45,400 net) acres of undeveloped land. The acquired properties were located in the Brooks area of southern Alberta, the Chinchaga area of northwestern Alberta, the Mitsue area of north central Alberta as well as in southeastern Saskatchewan and southwestern Manitoba.
 
Unitholder Limited Liability Legislation
 
        Effective July 1, 2004 the Income Trusts Liability Act (Alberta) was proclaimed in force. The Act created a statutory limitation on the liability of unitholders of income trusts organized under the laws of Alberta, such as the Fund. The legislation provides that a unitholder will not be, as a beneficiary, liable for any act, default, obligation or liability of the trustee that arises after the legislation comes into effect. The legislation does not affect the liability of unitholders with respect to any act, default, obligation or liability that arose before July 1, 2004. Additionally, in December 2004 Ontario adopted unitholder limited liability legislation similar to that implemented in Alberta. The Province of Québec historically had codified limited liability for trust unitholders and certain other provinces have adopted similar unitholder liability legislation. For additional information, see "Risk Factors — Risks Related to Enerplus' Structure and the Ownership of the Trust Units — The limited liability of the Fund's unitholders is uncertain".
 
Acquisition of TriLoch Resources Inc.
 
        On July 1, 2005, Enerplus completed the acquisition of TriLoch Resources Inc. ("TriLoch"). Pursuant to a plan of arrangement, Enerplus issued 1,632,516 Trust Units in exchange for all of the shares of TriLoch. The Trust Unit value of $42.32 was based upon the weighted average price of the Fund's Trust Units on the TSX during the five day trading period surrounding the announcement of the transaction on May 17, 2005. Total consideration was approximately $77.4 million consisting of Trust Units, transaction costs and the retirement of TriLoch's bank indebtedness. Enerplus also assumed a working capital deficiency of $0.4 million. The TriLoch acquisition complemented Enerplus' existing asset base in the Enchant area of southern Alberta. Production from the area was weighted approximately 68% to natural gas and 32% to crude oil and NGLs at the time of the acquisition.
 
 
 
3

 

Acquisition of Lyco Energy Corporation and Sleeping Giant LLC
 
        On August 30, 2005, Enerplus acquired all of the outstanding shares, and retired the debt (including mandatory redeemable preferred shares) of Lyco Energy Corporation ("Lyco"), a private Delaware corporation operating in the states of Montana and North Dakota. The total consideration paid for Lyco was approximately $501.9 million and Enerplus also assumed a working capital deficiency of $4.4 million. In connection with the acquisition, the Fund issued 10,637,500 Trust Units (issued upon the automatic conversion of subscription receipts upon the closing of the Lyco transaction) at a price of $46.25 for gross proceeds of $492.0 million (net proceeds of $466.9 million). Production from the Lyco properties was weighted approximately 92% light oil and 8% natural gas at the time of the acquisition. These properties predominantly produce high quality, Middle Bakken light oil from the Sleeping Giant project area. The acquisition also provided Enerplus with approximately 120,000 net acres of undeveloped land in both Montana and North Dakota.
 
        On October 4, 2005, Enerplus completed the acquisition of Sleeping Giant LLC, a private U.S. company. Total consideration paid for Sleeping Giant LLC was approximately $111.9 million and was financed through existing credit facilities. Enerplus also assumed positive working capital of $5.8 million. The assets of Sleeping Giant LLC consisted of additional working interests in the Sleeping Giant light crude oil project in Montana that formed part of the earlier Lyco acquisition. This acquisition increased Enerplus' working interest in certain producing wells in the Sleeping Giant project to an approximate 70% working interest. This acquisition was accounted for as an asset acquisition in accordance with GAAP.
 
        Sleeping Giant LLC was subsequently merged with Lyco, and on February 9, 2006 Lyco merged with Enerplus Newco LLC and continued as Enerplus Resources (USA) Corporation.
 
        The Lyco and Sleeping Giant LLC acquisitions were Enerplus' first acquisitions of U.S. assets. On February 21, 2006 Enerplus opened an office in Denver, Colorado to support the ongoing operation of its assets in Montana and North Dakota and to facilitate future growth in the United States.
 
Participation in Joslyn Project and Other Oil Sands Projects
 
        Enerplus initially acquired a 16% working interest in the Joslyn Project in 2002. The remaining 84% working interest is owned by Total, which acquired the original operator and majority owner of the Joslyn Project (Deer Creek Energy Limited) in 2005. Total is the operator of the Joslyn Project. For a description of the status and operations of the Joslyn Project, see "Operational Information — Description of Principal Properties and Operations — Oil Sands".
 
        In early 2006, Enerplus sold a 1% working interest in the Joslyn Project in exchange for equity in Laricina Energy Ltd., a new private oil sands focused company led by the former Chief Executive Officer of Deer Creek Energy Limited prior to its acquisition by Total. Included in the sale is an area of mutual interest agreement which has been designed to allow Enerplus and Laricina to jointly pursue additional in-situ oil sands ventures.
 
S&P/TSX Index Inclusion
 
        In 2005, Standard and Poor's announced that it would include income trusts, including Enerplus, in the S&P/TSX Composite Index. Income trusts were given one-half of their respective weightings in the S&P/TSX Composite Index in December 2005 and the remaining one-half weighting occurred in mid-March 2006.
 
Federal Government Pronouncements on Income Trusts
 
        On October 31, 2006, the Canadian federal government (the "Government") announced plans to introduce a tax on publicly traded income trusts (other than real estate investment trusts) to generally tax income trusts at the same effective tax rates as Canadian corporations (the "Income Trust Tax Proposals"). For existing income trusts, such as the Fund, the new tax measures would not be effective until 2011, provided that such trusts comply with certain "normal growth" parameters regarding equity growth until that time. Those parameters are designed to ensure that income trusts do not undertake what the Government has deemed to be "undue expansion" in an attempt to circumvent the Government's intention to halt the growth of the income trust industry in Canada. A "Notice of Ways and Means Motion" was passed in the Canadian Parliament shortly after
 
 
 
4

 

the Government announcement. This notice was a one-page summary of the Income Trust Tax Proposals and it did not identify any specific amendments to the Tax Act.
 
        On December 15, 2006, the Government announced guidance regarding a "normal growth" safe harbour for future issuances of equity capital. The safe harbour amount will be measured by reference to the individual trust's market capitalization as of the end of trading on October 31, 2006 (which was approximately $7.5 billion for the Fund). For the period from November 1, 2006 to December 31, 2007, a trust's safe harbour amount will be 40 percent of the October 31, 2006 market capitalization benchmark, and for each of the years 2008 through and including 2010 a trust's safe harbour amount will be 20 percent of the benchmark, cumulatively allowing equity growth of up to 100 percent until 2011. In addition, Enerplus understands that income trusts will be able to issue equity to retire debt existing on October 31, 2006 without eroding their safe harbour limits. The guidance regarding "normal growth" is administrative in nature and is not law and can be revised without an Act of the Canadian Parliament.
 
        On December 21, 2006, the Government released draft legislative proposals to amend the Tax Act with respect to the Income Trust Tax Proposals and requested comments from stakeholders. In late January 2007 the House of Commons Standing Committee on Finance (the "Standing Committee") held special hearings on the Income Trust Tax Proposals and the draft legislation. On February 28, 2007, the Standing Committee released its report that recommended, among other things, that the proposed income trust tax be reduced from 31.5% to 10% with such tax to commence immediately and be refundable to Canadian investors or that the proposed transition period be extended from four years to ten years. The Government is not bound by any of the report recommendations and it is expected that the Government will proceed with the Income Trust Tax Proposals in their original form. As a result, at this time Enerplus is unable to determine the impact, if any, this report may have on the Income Trust Tax Proposals.
 
        At this time, the draft legislation to give effect to the Income Trust Tax Proposals has not yet been introduced into the Canadian House of Commons and therefore has not been approved or declared in force by the Government. Accordingly, it is uncertain when the proposed legislation could be passed by the Canadian Parliament, if at all, or as to what form, if any, changes in Canadian income tax laws will take as a result of such proposal. Should the proposed tax legislation become substantially enacted, the Fund's future income taxes disclosed in its financial statements may be adjusted to include temporary differences between the accounting and tax bases of the Fund's assets and liabilities. In addition, the reported estimated net present value of future net revenues from Enerplus' oil and natural gas reserves may be adjusted to include an estimate of such revenues on an "after-tax" basis to reflect the impact of the income trust tax. Subject to clarity through the legislative process, Enerplus will assess alternative organizational structures during the four year transition period.
 
        For additional information, see "Oil and Natural Gas Reserves — Overview of Reserves", "Operational Information — Tax Horizon" and "Risk Factors — Risks Relating to Enerplus' Structure and Ownership of the Trust Units" in this Annual Information Form.
 
Events Subsequent to 2006 Year-End
 
Acquisition of Gross Overriding Royalty Interests in U.S.
 
        On January 31, 2007, Enerplus acquired various gross overriding royalty ("GORR") interests in the state of Wyoming for total consideration of US$52 million (CDN$60 million). This acquisition represents a modest addition to Enerplus' assets in the United States and establishes a new area which Enerplus believes has significant natural gas development potential.
 
        The subject assets produce natural gas from the EnCana Corporation-operated Jonah gas field in Wyoming, which is one of the largest natural gas fields in the U.S. The acquisition consisted of a GORR of approximately 0.5% on approximately 650 producing natural gas wells in the Jonah field. Enerplus has acquired a net royalty interest that is equivalent to approximately 540 BOE/d of daily production and approximately 2.2 million BOE of Proved Reserves and 2.9 million BOE of Proved plus Probable Reserves based on independent third party engineering evaluations effective December 31, 2006. Enerplus believes the field has a significant number of additional infill drilling locations that will provide growth potential for the future. Enerplus will not be required to expend any future development capital on the assets. Enerplus expects the net operating cash flow per BOE, net of all applicable U.S. taxes, to be significantly higher than that of its existing production due to the nature of the GORR which is not subject to deductions for operating costs and royalties.
 
 
 
5

 

OIL AND NATURAL GAS RESERVES
 
Overview of Reserves
 
        All of Enerplus' reserves, including its U.S. reserves, have been evaluated in accordance with NI 51-101. Sproule Associates Limited, a firm of independent petroleum engineers based in Calgary, Alberta, has evaluated properties which comprise approximately 90% of the net present value (discounted at 10%, using forecast prices and costs) of Enerplus' Proved plus Probable Canadian conventional oil and natural gas reserves. Enerplus has evaluated the balance of the Canadian conventional properties using similar evaluation parameters, including the same forecast price, inflation and exchange rate assumptions utilized by Sproule. Sproule has reviewed Enerplus' evaluation of these properties.
 
        DeGolyer and MacNaughton, independent petroleum consultants based in Dallas, Texas, has evaluated all of Enerplus' conventional oil and natural gas reserves located in the United States. For internal consistency in Enerplus' reserves reporting, D&M has used Sproule's forecast prices, inflation and exchange rates.
 
        GLJ Petroleum Consultants Ltd., a private independent petroleum consulting firm based in Calgary, Alberta, has evaluated all of Enerplus' interests in the SAGD-recoverable bitumen reserves of the Joslyn Project, again using the same forecast price, inflation and exchange rate assumptions utilized by Sproule.
 
        The following tables summarize, as at December 31, 2006, Enerplus' oil, NGLs and natural gas reserves and the estimated net present values of future net revenues associated with such reserves, together with certain information, estimates and assumptions associated with such reserve estimates. The following reserves information does not include the various gross overriding royalty interests in Wyoming, U.S.A. acquired by Enerplus on January 31, 2007 as described under "General Development of Enerplus Resources Fund — Events Subsequent to 2006 Year-End — Acquisition of Gross Overriding Royalty Interests in U.S.". The data contained in the tables is a summary of the evaluations, and as a result the tables may contain slightly different numbers than the evaluations themselves due to rounding. Additionally, the numbers in the tables may not add due to rounding. All of Enerplus' bitumen reserves are located in Canada.
 
        All estimates of future net revenues are stated prior to provision for interest and general and administrative expenses and after deduction of royalties and estimated future capital expenditures, and both before and after income taxes (which currently only consist of income taxes related to U.S. operations). All estimates of future net revenues associated with Enerplus' oil, NGLs and natural gas reserves are presented on the basis that Enerplus will not pay cash income taxes in Canada in the future due to Enerplus' current structure as an income trust and Canadian tax laws currently in effect, and do not give effect to the Income Trust Tax Proposals. Enerplus' U.S. operations are subject to cash income taxes, and as a result Enerplus' U.S. reserves are disclosed net of the taxes Enerplus estimates will be payable after taking into account inter-company debt within Enerplus' structure. The Canadian federal government has announced the Income Trust Tax Proposals which are designed to generally tax income trusts such as Enerplus at the same effective tax rates as Canadian corporations, effective for the 2011 tax year. Such proposals are not yet approved or in force and it is uncertain as to what form, if any, changes in Canadian income tax laws will take as a result of such proposal. Any changes in Canadian income tax laws that may result from the Income Trust Tax Proposals could adversely affect the estimated future net revenues associated with Enerplus' oil and gas reserves. If the draft legislation designed to give effect to the Income Trust Tax Proposals is enacted as currently proposed, Enerplus intends to provide updated reserves information which would present the estimated future net revenues from Enerplus' reserves on an after-tax basis that would reflect the impact of the income trust tax. For additional information, see "General Development of Enerplus Resources Fund — Developments in the Past Three Years — Federal Government Pronouncements on Income Trusts", "Operational Information — Tax Horizon" and "Risk Factors — Risks Relating to Enerplus' Structure and Ownership of the Trust Units" in this Annual Information Form.
 
        With respect to pricing information in the following reserves information, the wellhead oil prices were adjusted for quality and transportation based on historical actual prices. The natural gas prices were adjusted, where necessary, based on historical pricing based on heating values and the differing costs of service applied by various purchasers. The NGLs prices were adjusted to reflect historical average prices received.
 
        It should not be assumed that the present worth of estimated future cash flows shown below is representative of the fair market value of the reserves. There is no assurance that such price and cost assumptions will be attained and variances could be material. The recovery and reserve estimates of Enerplus' crude oil, NGLs and
 
 
 
6

 

natural gas reserves provided herein are estimates only. Actual reserves may be greater than or less than the estimates provided herein. Readers should review the definitions and information contained in "Presentation of Enerplus' Oil and Gas Reserves, Resources and Production Information" in conjunction with the following tables and notes.
 
Summary of Aggregate Enerplus Reserves
 
        The following tables summarize the aggregate company interest reserves volumes and net present value of future net revenue contained in the Sproule Report relating to Enerplus' Canadian conventional crude oil and natural gas reserves, the D&M Report relating to Enerplus' U.S. conventional crude oil and natural gas reserves and the GLJ Reserves Report relating to Enerplus' interest in the SAGD-recoverable bitumen reserves of the Joslyn Project, all based on Sproule's forecast price and cost assumptions. Detailed separate summaries of the Sproule Report, the D&M Report and the GLJ Reserves Report, including certain assumptions incorporated into those reports, and presentation of Enerplus' oil and gas reserves in accordance with NI 51-101 are contained in the tables following the summary report below.

Summary of Aggregate Oil and Gas Reserves
As of December 31, 2006

Company Interest Reserves,
Forecast Prices and Costs
 
  OIL AND GAS NATURAL RESERVES  
RESERVES CATEGORY   Light &
Medium Oil
  Heavy Oil   Bitumen   Total Oil   Natural Gas Liquids   Natural Gas   Total  
    (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (MMcf)   (MBOE)  
Proved Developed Producing                                            
    Canada
    66,458     28,932     2,479     97,869     11,434     727,596     230,569  
    United States
    21,933             21,933         13,626     24,204  
    Total
    88,391     28,932     2,479     119,802     11,434     741,222     254,773  
Proved Developed Non-Producing                                            
    Canada
    537             537     621     17,317     4,044  
    United States
    871             871         724     992  
    Total
    1,408             1,408     621     18,041     5,036  
Proved Undeveloped                                            
    Canada
    3,509     2,221     6,251     11,981     635     160,348     39,341  
    United States
    587             587         450     662  
    Total
    4,096     2,221     6,251     12,568     635     160,798     40,003  
Total Proved                                            
    Canada
    70,504     31,153     8,730     110,387     12,690     905,261     273,954  
    United States
    23,391             23,391         14,800     25,858  
    Total
    93,895     31,153     8,730     133,778     12,690     920,061     299,812  
Probable                                            
    Canada
    16,872     8,912     47,998     73,782     3,777     306,804     128,693  
    United States
    8,637             8,637         37,221     14,840  
    Total
    25,509     8,912     47,998     82,419     3,777     344,025     143,533  
Total Proved plus Probable                                            
    Canada
    87,376     40,065     56,728     184,169     16,467     1,212,065     402,647  
    United States
    32,028             32,028         52,021     40,698  
    Total
    119,404     40,065     56,728     216,197     16,467     1,264,086     443,345  
 
 
 
7

 

Summary of Aggregate Net Present Value
of Future Net Revenue Attributable to Oil and Gas Reserves
As of December 31, 2006

Company Interest Reserves,
Forecast Prices and Costs
 

 
 
NET PRESENT VALUE OF FUTURE NET REVENUE DISCOUNTED AT (%/YEAR)
 
 
 
Before Deducting Income Taxes
 
After Deducting Income Taxes
 
RESERVES CATEGORY
 
0%
 
5%
 
10%
 
15%
 
20%
 
0%
 
5%
 
10%
 
15%
 
20%
 
 
 
(in $ millions)
 
CONVENTIONAL OIL AND GAS RESERVES
                                         
Proved Developed Producing
                                         
    Canada
   
6,705
   
4,479
   
3,464
   
2,877
   
2,489
   
6,705
   
4,479
   
3,464
   
2,877
   
2,489
 
    United States
   
1,064
   
821
   
668
   
565
   
491
   
804
   
624
   
509
   
431
   
375
 
    Total
   
7,769
   
5,300
   
4,132
   
3,442
   
2,980
   
7,509
   
5,103
   
3,973
   
3,308
   
2,864
 
Proved Developed Non-Producing
                                         
    Canada
   
120
   
75
   
56
   
45
   
39
   
120
   
75
   
56
   
45
   
39
 
    United States
   
39
   
29
   
24
   
20
   
16
   
25
   
19
   
16
   
13
   
10
 
    Total
   
159
   
104
   
80
   
65
   
55
   
145
   
94
   
72
   
58
   
49
 
Proved Undeveloped
                                         
    Canada
   
556
   
385
   
272
   
196
   
142
   
556
   
385
   
272
   
196
   
142
 
    United States
   
22
   
15
   
11
   
8
   
6
   
26
   
16
   
10
   
7
   
5
 
    Total
   
578
   
400
   
283
   
204
   
148
   
582
   
401
   
282
   
203
   
147
 
Total Proved
                                         
    Canada
   
7,381
   
4,939
   
3,792
   
3,118
   
2,670
   
7,381
   
4,939
   
3,792
   
3,118
   
2,670
 
    United States
   
1,125
   
865
   
703
   
593
   
513
   
855
   
659
   
535
   
451
   
390
 
    Total Proved Conventional Reserves
   
8,506
   
5,804
   
4,495
   
3,711
   
3,183
   
8,236
   
5,598
   
4,327
   
3,569
   
3,060
 
Probable
                                         
    Canada
   
2,721
   
1,242
   
745
   
516
   
387
   
2,721
   
1,242
   
745
   
516
   
387
 
    United States
   
630
   
333
   
198
   
128
   
88
   
419
   
217
   
126
   
78
   
51
 
    Total Probable Conventional Reserves
   
3,351
   
1,575
   
943
   
644
   
475
   
3,140
   
1,459
   
871
   
594
   
438
 
Total Proved Plus Probable Conventional Reserves
   
11,857
   
7,379
   
5,438
   
4,355
   
3,658
   
11,376
   
7,057
   
5,198
   
4,163
   
3,498
 
BITUMEN RESERVES
                                                             
    Proved Developed Producing
   
20
   
16
   
13
   
11
   
10
   
20
   
16
   
13
   
11
   
10
 
    Proved Undeveloped
   
39
   
20
   
10
   
4
   
1
   
39
   
20
   
10
   
4
   
1
 
Total Proved
   
59
   
36
   
23
   
15
   
11
   
59
   
36
   
23
   
15
   
11
 
    Probable
   
453
   
104
   
25
   
2
   
(8
)
 
453
   
104
   
25
   
2
   
(8
)
Total Proved Plus Probable Bitumen Reserves
   
512
   
140
   
48
   
17
   
3
   
512
   
140
   
48
   
17
   
3
 
TOTAL CONVENTIONAL RESERVES AND BITUMEN RESERVES
   
12,369
   
7,519
   
5,486
   
4,372
   
3,661
   
11,888
   
7,197
   
5,246
   
4,180
   
3,501
 
 
 
 
8

 
Summary of Conventional Oil and Natural Gas Reserves
 
        The following tables and notes summarize the reserves volumes and net present value of future net revenue attributable to Enerplus' conventional oil and gas reserves, including certain assumptions relating to the determination of those reserves and values. All information relating to Canadian conventional reserves is contained in the Sproule Report and all information relating to United States conventional reserves is contained in the D&M Report.

Summary of Conventional Oil and Gas Reserves
As of December 31, 2006

Forecast Prices and Costs
 
 
 
OIL AND NATURAL GAS RESERVES
 
 
 
Light & Medium Oil
 
Heavy Oil
 
Natural Gas
 
RESERVES CATEGORY
 
Company
Interest
 
Gross
 
Net
 
Company
Interest
 
Gross
 
Net
 
Company
Interest
 
Gross
 
Net
 
 
 
(Mbbls)
 
(Mbbls)
 
(Mbbls)
 
(Mbbls)
 
(Mbbls)
 
(Mbbls)
 
(MMcf)
 
(MMcf)
 
(MMcf)
 
Proved Developed Producing
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    Canada
 
 
66,458
 
 
65,681
 
 
60,673
 
 
28,932
 
 
28,911
 
 
25,889
 
 
727,596
 
 
704,228
 
 
587,410
 
    United States
 
 
21,933
 
 
21,933
 
 
18,280
 
 
 
 
 
 
 
 
13,626
 
 
13,626
 
 
11,375
 
    Total
 
 
88,391
 
 
87,614
 
 
78,953
 
 
28,932
 
 
28,911
 
 
25,889
 
 
741,222
 
 
717,854
 
 
598,785
 
Proved Developed Non-Producing
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    Canada
 
 
537
 
 
537
 
 
277
 
 
 
 
 
 
 
 
17,317
 
 
16,897
 
 
13,562
 
    United States
 
 
871
 
 
871
 
 
727
 
 
 
 
 
 
 
 
724
 
 
724
 
 
608
 
    Total
 
 
1,408
 
 
1,408
 
 
1,004
 
 
 
 
 
 
 
 
18,041
 
 
17,621
 
 
14,170
 
Proved Undeveloped
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    Canada
 
 
3,509
 
 
3,500
 
 
3,184
 
 
2,221
 
 
2,219
 
 
1,890
 
 
160,348
 
 
156,655
 
 
136,033
 
    United States
 
 
587
 
 
587
 
 
493
 
 
 
 
 
 
 
 
450
 
 
450
 
 
377
 
    Total
 
 
4,096
 
 
4,087
 
 
3,677
 
 
2,221
 
 
2,219
 
 
1,890
 
 
160,798
 
 
157,105
 
 
136,410
 
Total Proved Reserves
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    Canada
 
 
70,504
 
 
69,718
 
 
64,134
 
 
31,153
 
 
31,130
 
 
27,779
 
 
905,261
 
 
877,780
 
 
737,005
 
    United States
 
 
23,391
 
 
23,391
 
 
19,500
 
 
 
 
 
 
 
 
14,800
 
 
14,800
 
 
12,360
 
    Total
 
 
93,895
 
 
93,109
 
 
83,634
 
 
31,153
 
 
31,130
 
 
27,779
 
 
920,061
 
 
892,580
 
 
749,365
 
Probable Reserves
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    Canada
 
 
16,872
 
 
16,690
 
 
15,077
 
 
8,912
 
 
8,903
 
 
8,035
 
 
306,804
 
 
299,699
 
 
253,635
 
    United States
 
 
8,637
 
 
8,637
 
 
7,091
 
 
 
 
 
 
 
 
37,221
 
 
37,221
 
 
30,985
 
    Total
 
 
25,509
 
 
25,327
 
 
22,168
 
 
8,912
 
 
8,903
 
 
8,035
 
 
344,025
 
 
336,920
 
 
284,620
 
Total Proved Plus Probable Reserves
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    Canada
 
 
87,376
 
 
86,408
 
 
79,211
 
 
40,065
 
 
40,033
 
 
35,814
 
 
1,212,065
 
 
1,177,479
 
 
990,640
 
    United States
 
 
32,028
 
 
32,028
 
 
26,591
 
 
 
 
 
 
 
 
52,021
 
 
52,021
 
 
43,345
 
    Total
 
 
119,404
 
 
118,436
 
 
105,802
 
 
40,065
 
 
40,033
 
 
35,814
 
 
1,264,086
 
 
1,229,500
 
 
1,033,985
 
 
(continues on next page)
 
 
 
9

 
(continued)
 
 
 
OIL AND NATURAL GAS RESERVES
 
 
 
Natural Gas Liquids
 
Total
 
RESERVES CATEGORY
 
Company
Interest
 
Gross
 
Net
 
Company
Interest
 
Gross
 
Net
 
 
 
(Mbbls)
 
(Mbbls)
 
(Mbbls)
 
(MBOE)
 
(MBOE)
 
(MBOE)
 
Proved Developed Producing
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    Canada
 
 
11,434
 
 
11,241
 
 
7,978
 
 
228,090
 
 
223,205
 
 
192,441
 
    United States
 
 
 
 
 
 
 
 
24,204
 
 
24,204
 
 
20,175
 
    Total
 
 
11,434
 
 
11,241
 
 
7,978
 
 
252,294
 
 
247,409
 
 
212,616
 
Proved Developed Non-Producing
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    Canada
 
 
621
 
 
606
 
 
437
 
 
4,044
 
 
3,958
 
 
2,975
 
    United States
 
 
 
 
 
 
 
 
992
 
 
992
 
 
828
 
    Total
 
 
621
 
 
606
 
 
437
 
 
5,036
 
 
4,950
 
 
3,803
 
Proved Undeveloped
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    Canada
 
 
635
 
 
634
 
 
441
 
 
33,090
 
 
32,462
 
 
28,187
 
    United States
 
 
 
 
 
 
 
 
662
 
 
662
 
 
556
 
    Total
 
 
635
 
 
634
 
 
441
 
 
33,752
 
 
33,124
 
 
28,743
 
Total Proved Reserves
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    Canada
 
 
12,690
 
 
12,481
 
 
8,856
 
 
265,224
 
 
259,625
 
 
223,603
 
    United States
 
 
 
 
 
 
 
 
25,858
 
 
25,858
 
 
21,559
 
    Total
 
 
12,690
 
 
12,481
 
 
8,856
 
 
291,082
 
 
285,483
 
 
245,162
 
Probable Reserves
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    Canada
 
 
3,777
 
 
3,708
 
 
2,665
 
 
80,695
 
 
79,252
 
 
68,049
 
    United States
 
 
 
 
 
 
 
 
14,840
 
 
14,840
 
 
12,256
 
    Total
 
 
3,777
 
 
3,708
 
 
2,665
 
 
95,535
 
 
94,092
 
 
80,305
 
Total Proved Plus Probable Reserves
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    Canada
 
 
16,467
 
 
16,189
 
 
11,521
 
 
345,919
 
 
338,877
 
 
291,652
 
    United States
 
 
 
 
 
 
 
 
40,698
 
 
40,698
 
 
33,815
 
    Total
 
 
16,467
 
 
16,189
 
 
11,521
 
 
386,617
 
 
379,575
 
 
325,467
 
 
 
 
 
 
10

 
Summary of Net Present Value of Future Net Revenue
Attributable to Conventional Oil and Gas Reserves
As of December 31, 2006
 
Forecast Prices and Costs
 
 
 
NET PRESENT VALUE OF FUTURE NET REVENUE DISCOUNTED AT (%/YEAR)
 
 
 
Before Deducting Income Taxes
 
After Deducting Income Taxes
 
RESERVES CATEGORY
 
0%
 
5%
 
10%
 
15%
 
20%
 
0%
 
5%
 
10%
 
15%
 
20%
 
 
 
(in $ millions)
 
Proved Developed Producing
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    Canada
 
 
6,705
 
 
4,479
 
 
3,464
 
 
2,877
 
 
2,489
 
 
6,705
 
 
4,479
 
 
3,464
 
 
2,877
 
 
2,489
 
    United States
 
 
1,064
 
 
821
 
 
668
 
 
565
 
 
491
 
 
804
 
 
624
 
 
509
 
 
431
 
 
375
 
    Total
 
 
7,769
 
 
5,300
 
 
4,132
 
 
3,442
 
 
2,980
 
 
7,509
 
 
5,103
 
 
3,973
 
 
3,308
 
 
2,864
 
Proved Developed Non-Producing
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    Canada
 
 
120
 
 
75
 
 
56
 
 
45
 
 
39
 
 
120
 
 
75
 
 
56
 
 
45
 
 
39
 
    United States
 
 
39
 
 
29
 
 
24
 
 
20
 
 
16
 
 
25
 
 
19
 
 
16
 
 
13
 
 
10
 
    Total
 
 
159
 
 
104
 
 
80
 
 
65
 
 
55
 
 
145
 
 
94
 
 
72
 
 
58
 
 
49
 
Proved Undeveloped
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    Canada
 
 
556
 
 
385
 
 
272
 
 
196
 
 
142
 
 
556
 
 
385
 
 
272
 
 
196
 
 
142
 
    United States
 
 
22
 
 
15
 
 
11
 
 
8
 
 
6
 
 
26
 
 
16
 
 
10
 
 
7
 
 
5
 
    Total
 
 
578
 
 
400
 
 
283
 
 
204
 
 
148
 
 
582
 
 
401
 
 
282
 
 
203
 
 
147
 
Total Proved
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    Canada
 
 
7,381
 
 
4,939
 
 
3,792
 
 
3,118
 
 
2,670
 
 
7,381
 
 
4,939
 
 
3,792
 
 
3,118
 
 
2,670
 
    United States
 
 
1,125
 
 
865
 
 
703
 
 
593
 
 
513
 
 
855
 
 
659
 
 
535
 
 
451
 
 
390
 
    Total
 
 
8,506
 
 
5,804
 
 
4,495
 
 
3,711
 
 
3,183
 
 
8,236
 
 
5,598
 
 
4,327
 
 
3,569
 
 
3,060
 
Probable
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    Canada
 
 
2,721
 
 
1,242
 
 
745
 
 
516
 
 
387
 
 
2,721
 
 
1,242
 
 
745
 
 
516
 
 
387
 
    United States
 
 
630
 
 
333
 
 
198
 
 
128
 
 
88
 
 
419
 
 
217
 
 
126
 
 
78
 
 
51
 
    Total
 
 
3,351
 
 
1,575
 
 
943
 
 
644
 
 
475
 
 
3,140
 
 
1,459
 
 
871
 
 
594
 
 
438
 
Total Proved Plus Probable
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    Canada
 
 
10,102
 
 
6,181
 
 
4,537
 
 
3,634
 
 
3,057
 
 
10,102
 
 
6,181
 
 
4,537
 
 
3,634
 
 
3,057
 
    United States
 
 
1,755
 
 
1,198
 
 
901
 
 
721
 
 
601
 
 
1,274
 
 
876
 
 
661
 
 
529
 
 
441
 
    Total
 
 
11,857
 
 
7,379
 
 
5,438
 
 
4,355
 
 
3,658
 
 
11,376
 
 
7,057
 
 
5,198
 
 
4,163
 
 
3,498
 
 
 
 
11

 
Summary of Conventional Oil and Gas Reserves
As of December 31, 2006

Constant Prices and Costs
 
 
 
OIL AND NATURAL GAS RESERVES
 
 
 
Light & Medium Oil
 
Heavy Oil
 
Natural Gas
 
RESERVES CATEGORY
 
Company Interest
 
Gross
 
Net
 
Company Interest
 
Gross
 
Net
 
Company
Interest
 
Gross
 
Net
 
 
 
(Mbbls)
 
(Mbbls)
 
(Mbbls)
 
(Mbbls)
 
(Mbbls)
 
(Mbbls)
 
(MMcf)
 
(MMcf)
 
(MMcf)
 
Proved Developed Producing
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    Canada
 
 
66,969
 
 
66,192
 
 
61,156
 
 
29,050
 
 
29,030
 
 
25,993
 
 
708,394
 
 
685,157
 
 
571,488
 
    United States
 
 
21,898
 
 
21,898
 
 
18,250
 
 
 
 
 
 
 
 
13,602
 
 
13,602
 
 
11,354
 
    Total
 
 
88,867
 
 
88,090
 
 
79,406
 
 
29,050
 
 
29,030
 
 
25,993
 
 
721,996
 
 
698,759
 
 
582,842
 
Proved Developed Non-Producing
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    Canada
 
 
541
 
 
541
 
 
284
 
 
 
 
 
 
 
 
17,078
 
 
16,641
 
 
13,358
 
    United States
 
 
870
 
 
870
 
 
727
 
 
 
 
 
 
 
 
723
 
 
723
 
 
607
 
    Total
 
 
1,411
 
 
1,411
 
 
1,011