EX-99.1 2 a2197056zex-99_1.htm EXHIBIT 99.1
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EXHIBIT 99.1


 
 
 
 
 
 

GRAPHIC

 
 
 
 
 
 
 
 
 

ANNUAL INFORMATION FORM
For the year ended December 31, 2009

 
 
 
 
 
 
 
 
 

March 12, 2010



Table of Contents

 
   
GLOSSARY OF TERMS   i
ABBREVIATIONS AND CONVERSIONS   iv
PRESENTATION OF ENERPLUS' OIL AND GAS RESERVES, RESOURCES AND PRODUCTION INFORMATION   v
PRESENTATION OF ENERPLUS' FINANCIAL INFORMATION   viii
FORWARD-LOOKING STATEMENTS AND INFORMATION   viii
STRUCTURE OF ENERPLUS RESOURCES FUND   1
  Enerplus Resources Fund   1
  Operating Subsidiaries   1
  Organizational Structure   2
GENERAL DEVELOPMENT OF ENERPLUS RESOURCES FUND   3
  General   3
  Developments in the Past Three Years   3
BUSINESS OF ENERPLUS   6
  Overview   6
  Summary of Principal Production Locations   7
  Capital Expenditures and Costs Incurred   8
  Exploration and Development Activities   10
  Oil and Natural Gas Wells and Unproved Properties   11
  Enerplus' Resource Play Types   12
  Quarterly Production History   22
  Quarterly Netback History   23
  Abandonment and Reclamation Costs   25
  Tax Horizon   25
  Marketing Arrangements and Forward Contracts   26
OIL AND NATURAL GAS RESERVES   27
  Summary of Reserves   27
  Forecast Prices and Costs   34
  Constant Prices and Costs   34
  Undiscounted Future Net Revenue by Reserves Category   35
  Net Present Value of Future Net Revenue by Reserves Category   35
  Estimated Production for Gross Reserves Estimates   36
  Future Development Costs   36
  Reconciliation of Reserves   37
  Undeveloped Reserves   42
  Significant Factors or Uncertainties   42
  Proved and Probable Reserves Not On Production   42
SUPPLEMENTAL OPERATIONAL INFORMATION   43
  Health, Safety and Environment   43
  Insurance   44
  Personnel   44
INFORMATION RESPECTING ENERPLUS RESOURCES FUND   45
  Description of the Trust Units and the Trust Indenture   45
  Description of the Royalty Agreements and Other Payments Made to the Fund   51
  Management and Corporate Governance   52
  Unitholder Rights Plan   52
DEBT OF ENERPLUS   53
  Bank Credit Facility   53
  Senior Unsecured Notes   54
DISTRIBUTIONS TO UNITHOLDERS   56
  Cash Distributions   56
  Distribution History   57
  Canadian Tax Reporting Matters   57
  U.S. Tax Reporting Matters   57
INDUSTRY CONDITIONS   59
  Overview   59
  Pricing and Marketing – Oil   59
  Pricing and Marketing – Natural Gas   60
  The North America Free Trade Agreement   60
  Royalties and Incentives   60
  Land Tenure   61
  Environmental Regulation   61
  Worker Safety   63
RISK FACTORS   64
  Risks Related to Enerplus' Business and Operations   64
  Risks Related to Enerplus' Structure and the Ownership of the Trust Units   76
  Risks Particular to United States and Other Non-Resident Unitholders   80
MARKET FOR SECURITIES   82
DIRECTORS AND OFFICERS   83
  Directors of EnerMark   83
  Officers of EnerMark   84
  Trust Unit Ownership   84
  Conflicts of Interest   85
  Audit & Risk Management Committee Disclosure   85
LEGAL PROCEEDINGS AND REGULATORY ACTIONS   85
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS   85
MATERIAL CONTRACTS AND DOCUMENTS AFFECTING THE RIGHTS OF SECURITYHOLDERS   86
INTERESTS OF EXPERTS   86
REGISTRAR AND TRANSFER AGENT   87
ADDITIONAL INFORMATION   87
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 PURSUANT TO NATIONAL INSTRUMENT 52-110   E-1
APPENDIX F – SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES   F-1
APPENDIX G – INFORMATION REGARDING ENERPLUS EXCHANGEABLE LIMITED PARTNERSHIP   G-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".

"Bank Credit Facility" has the meaning assigned thereto under "Debt of Enerplus";

"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;

"CBM" means coalbed methane;

"Chief" means Chief Oil & Gas LLC, a Texas limited liability company, which is the operator of the Marcellus Properties;

"COGE Handbook" means the Canadian Oil and Gas Evaluation Handbook prepared jointly by The Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society), as amended from time to time;

"Credit Facilities" has the meaning assigned thereto under "Debt of Enerplus";

"CSA Notice 51-324" means Canadian Securities Administrators Staff Notice 51-324, Glossary to NI 51-101 Standards of Disclosure for Oil and Gas Activities, issued by the Canadian securities regulatory authorities;

"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;

"EELP" means Enerplus Exchangeable Limited Partnership, a limited partnership established under the laws of Alberta and a subsidiary of the Fund;

"EELP A Units" means the Class A limited partnership units of EELP, all of which are held, directly or indirectly, by the Fund;

"EELP Agreement" means the amended and restated limited partnership agreement dated February 13, 2008, as amended December 22, 2008, between EnerMark (as successor by amalgamation to FET Management Ltd.) and Focus Commercial Trust pursuant to which EELP is created, as may be amended, supplemented or restated from time to time;

"EELP Exchangeable LP Unitholders" means the holders from time to time of EELP Exchangeable LP Units;

"EELP Exchangeable LP Units" means the Class B limited partnership units of EELP, which are non-transferable and are exchangeable for no additional consideration into Trust Units on the basis of 0.425 of a Trust Unit for each EELP Exchangeable LP Unit;

"EELP General Partner" means EnerMark;

"EELP Support Agreement" means the amended and restated support agreement dated February 13, 2008 among the Fund, EELP and EnerMark (as successor by amalgamation to FET Management Ltd.), as may be amended, supplemented or restated from time to time;

"EELP Voting and Exchange Agreement" means the amended and restated voting and exchange trust agreement dated May 30, 2008 among the Fund, EELP and Computershare Trust Company of Canada, as may be amended, supplemented or restated from time to time;

"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 the Fund;

ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM      i


"ERC" means Enerplus Resources Corporation, a corporation organized under the Business Corporations Act (Alberta) and an indirect wholly-owned subsidiary of the Fund;

"Focus" means Focus Energy Trust, an oil and gas income trust acquired by Enerplus on February 13, 2008;

"Fund" means Enerplus Resources Fund;

"GAAP" means generally accepted accounting principles;

"GLJ" means GLJ Petroleum Consultants Ltd., independent petroleum consultants;

"GLJ Oil Sands Resources Report" means the independent engineering evaluation of the contingent and prospective resources attributable to Enerplus' interests in the Kirby Project (together with interests in certain minor non-operated oil sands projects) prepared by GLJ dated January 25, 2010 and effective December 31, 2009;

"Haas" means Haas Petroleum Engineering Services Inc., independent petroleum consultants;

"Haas Report" means the independent engineering evaluation of Enerplus' oil, NGLs and natural gas reserves and resources in the Marcellus Properties prepared by Haas dated January 27, 2010 and effective December 31, 2009, utilizing commodity price forecasts of McDaniel (for internal consistency in Enerplus' reserves reporting) as of January 1, 2010;

"Henry Hub" means the physical storage and trading hub in Louisiana which is the delivery point for the NYMEX natural gas contract;

"Kirby Lease" means, collectively, seven separate oil sands leases on a total area of 43,360 acres in the Kirby area of northeastern Alberta in Townships 073 through 075, Ranges 07 through 10, W4M, that expire on various dates from December 13, 2015 to September 27, 2021;

"Kirby Project" means the development of the Kirby Lease;

"Laricina" means Laricina Energy Ltd., a private oil sands corporation organized under the Business Corporations Act (Alberta);

"Marcellus Acquisition" means Enerplus' initial acquisition of an average 21.5% working interest in the Marcellus Properties on September 1, 2009 pursuant to the Marcellus Purchase Agreement and the Marcellus JDA;

"Marcellus AMI Agreements" has the meaning assigned thereto under "General Development of Enerplus Resources Fund – Developments in the Past Three Years – Acquisition of Interests in the Marcellus Properties";

"Marcellus Carry Amount" has the meaning assigned thereto under "General Development of Enerplus Resources Fund – Developments in the Past Three Years – Acquisition of Interests in the Marcellus Properties";

"Marcellus JDA" means the Joint Development Agreement dated September 1, 2009 among Enerplus USA and the Marcellus Vendors;

"Marcellus Properties" means approximately 540,000 gross acres in the Marcellus shale natural gas area, the majority of which is located in Pennsylvania with certain interests located in Maryland and West Virginia;

"Marcellus Purchase Agreement" means the purchase and sale agreement dated August 19, 2009 among Enerplus USA, as purchaser, and the Marcellus Vendors, which together with the Marcellus JDA provided for the Marcellus Acquisition;

"Marcellus Vendors" means, collectively, Chief, Chief Exploration & Development LLC (a Texas limited liability company) and a Texas limited partnership managed by Tug Hill, Inc.;

"McDaniel" means McDaniel & Associates Consultants Limited, independent petroleum consultants;

"McDaniel Report" means the independent engineering evaluation of Enerplus' Canadian conventional oil, NGLs and natural gas interests prepared by McDaniel dated February 12, 2010 and effective December 31, 2009, utilizing commodity price forecasts of McDaniel as of January 1, 2010;

"NI 51-101" means National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities, adopted by the Canadian securities regulatory authorities;

"NSAI" means Netherland, Sewell & Associates, Inc., independent petroleum consultants;

"NSAI Report" means the independent engineering evaluation of Enerplus' western United States oil, NGLs and natural gas interests prepared by NSAI dated January 27, 2010 and effective December 31, 2009, utilizing commodity price forecasts of McDaniel (for internal consistency in Enerplus' reserves reporting) as of January 1, 2010;

"NYSE" means the New York Stock Exchange;

ii      ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM


"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 as of December 31, 2009 being EnerMark, ERC, ECT, Enerplus USA and FET Operating Partnership);

"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;

"Senior Unsecured Notes" means, collectively, the US$494 million principal amount and $40 million principal amount of senior unsecured notes issued by EnerMark, as described under "Debt of Enerplus";

"SIFT Tax", "SIFT Provisions" and "SIFT Trust" each has the meaning ascribed thereto under "General Development of Enerplus Resources Fund – Developments in the Past Three Years – Changes to Taxation of Income Trusts and Enerplus' Strategy Post-2010";

"Special Voting Right" means the special voting right issued by the Fund to the Voting and Exchange Trustee entitling the holder thereof to vote, consent to, or otherwise act at a meeting or in respect of a resolution of the Fund's unitholders, and representing the number of votes that the EELP Exchangeable LP Unitholders would be entitled to had the EELP Exchangeable LP Unitholders exchanged all of the EELP Exchangeable LP Units then held by such holders for Trust Units immediately prior to the record date set for such meeting or at such other time as may be determined by applicable law for determining the Fund's unitholders entitled to so vote, consent or otherwise act at such a meeting or in respect of such a resolution;

"subsidiary" has the meaning assigned thereto in the Securities Act (Alberta);

"Tax Act" means the Income Tax Act (Canada), R.S.C. 1985, c.1 (5th Supp.), as amended, including the regulations promulgated thereunder, as amended from time to time;

"Trust Indenture" means the Amended and Restated Trust Indenture dated May 30, 2008 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 Computershare Trust Company of Canada, or its successor as trustee of the Fund;

"TSX" means the Toronto Stock Exchange; and

"Voting and Exchange Trustee" means Computershare Trust Company of Canada, or its successor as trustee under the EELP Voting and Exchange Agreement.

ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM      iii


Abbreviations and Conversions

In this Annual Information Form, the following abbreviations have the meanings set forth below.

AECO   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
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
Bcfe(1)   one billion cubic feet of natural gas equivalent
BOE(1)   barrels of oil equivalent
BOE/d   barrels of oil equivalent per day
Mbbls   one thousand barrels
MBOE(1)   one thousand barrels of oil equivalent
Mcf   one thousand cubic feet
Mcf/d   one thousand cubic feet per day
Mcfe(1)   one thousand cubic feet of natural gas equivalent
Mcfe/d   one thousand cubic feet of natural gas equivalent per day
MMbbls   one million barrels
MMBOE(1)   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
MMcfe(1)   one million cubic feet of natural gas equivalent
MMcfe/d   one million cubic feet of natural gas equivalent per day
NGLs   natural gas liquids
NYMEX   the New York Mercantile Exchange
Tcfe(1)   one trillion cubic feet of natural gas equivalent
WTI   West Texas Intermediate crude oil that serves as the benchmark crude oil for the NYMEX crude oil contract delivered in Cushing, Oklahoma

Note:

(1)
Enerplus has adopted the standard of 6 Mcf of natural gas: 1 bbl of oil when converting natural gas to BOEs, MBOEs and MMBOEs, and 1 bbl of oil and NGLs: 6 Mcf of natural gas when converting oil and NGLs to Mcfes, MMcfes, Bcfes and Tcfes. For further information, see "Presentation of Enerplus' Oil and Gas Reserves, Resources and Production Information – Barrels of Oil and Cubic Feet of Gas Equivalent".

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  

iv      ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM


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 reserves and operational information of Enerplus 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. Readers should also refer to the Report on Reserves Data by McDaniel attached hereto as Appendix A, the Report on Reserves Data by NSAI attached as Appendix B, the Report on Reserves Data by Haas 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, 2009 and the preparation date for such information is March 12, 2010. This Annual Information Form also contains certain supplemental operational and reserves information with respect to Enerplus not required to be disclosed under NI 51-101.

Certain of the following definitions and guidelines are contained in the Glossary to NI 51-101 contained in CSA Notice 51-324, which incorporates certain definitions from the COGE Handbook. Readers should consult CSA Notice 51-324 and the COGE Handbook for additional explanation and guidance.

DISCLOSURE OF RESERVES AND PRODUCTION INFORMATION

Presentation of 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 such oil and natural gas reserves does not represent the fair market value of such reserves. See "Oil and Natural Gas Reserves – Overview of Reserves" for additional information.

Notice to U.S. Readers

Data on oil and natural gas reserves contained in this Annual Information Form has generally been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects to United States or other foreign disclosure standards. For example, although the SEC now generally permits oil and gas issuers, in their filings with the SEC, to disclose both proved reserves and probable reserves (each as defined in the SEC rules), the SEC definitions of proved reserves and probable reserves may differ from the definitions of "Proved Reserves" and "Probable Reserves" under Canadian securities laws. In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using gross (or, as noted above, "company interest") volumes, which are volumes prior to deduction of royalty and similar payments. The practice in the United States is to report reserves and production using net volumes, after deduction of applicable royalties and similar payments. Moreover, in accordance with Canadian disclosure requirements, Enerplus has determined and disclosed estimated future net revenue from its reserves using forecast prices and costs, whereas the SEC now generally requires that reserve estimates be prepared using an unweighted average of the closing prices for the applicable commodity on the first day of the twelve months preceding the company's fiscal year-end, with the option of also disclosing reserve estimates based upon future or other prices. Enerplus has also provided certain supplemental information in this Annual Information Form (presented as "constant prices": see " – Description of Price and Cost Assumptions" below) in accordance with the SEC's pricing requirements. As a consequence of the foregoing, Enerplus' reserve estimates and production volumes may not be comparable to those made by companies utilizing United States reporting and disclosure standards. Additionally, the SEC prohibits disclosure of oil and gas resources, including contingent resources, whereas Canadian issuers may disclose oil and gas resources. Resources are different than, and should not be construed as, reserves. For a description of the definition of, and the risks and uncertainties surrounding the disclosure of, contingent resources, see " – Disclosure of Contingent Resources" below.

ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM      v


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 the Financial Accounting Standards Board's Accounting Standards Update (ASU) No. 2010-03 "Extractive Activies – Oil and Gas (Topic) 932", which disclosure complies with the SEC's guidelines regarding disclosure of oil and gas reserves.

BARRELS OF OIL AND CUBIC FEET OF GAS EQUIVALENT

Enerplus has adopted the standard of 6 Mcf of natural gas: 1 bbl of oil when converting natural gas to BOEs, MBOEs and MMBOEs, and 1 bbl of oil and NGLs: 6 Mcf of natural gas when converting oil and NGLs to Mcfes, MMcfes, Bcfes and Tcfes. BOEs, MBOEs, MMBOEs, Mcfes, MMcfes, Bcfes and Tcfes may be misleading, particularly if used in isolation. The foregoing conversion ratios are based on an energy equivalency conversion method primarily applicable at the burner tip and do not represent a value equivalency at the wellhead.

DISCLOSURE OF CONTINGENT RESOURCES

In this Annual Information Form, Enerplus has disclosed estimated volumes of "contingent resources" that have been prepared by GLJ pursuant to the GLJ Oil Sands Resources Report and which relate to the Kirby Lease and which have been prepared by Haas pursuant to the Haas Report and which relate to Enerplus' interest in the Marcellus Properties.

"Resources" are quantities of petroleum that are estimated to exist originally in naturally occurring accumulations, including the quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered.

"Contingent resources" are defined as those quantities of hydrocarbons estimated, on a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as "contingent resources" the estimated discovered recoverable quantities associated with a project in the early project stage.

Resources and contingent resources do not constitute, and should not be confused with, reserves. See "Business of Enerplus – Enerplus' Resource Play Types – Oil Sands" and "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".

INTERESTS IN RESERVES, PRODUCTION, WELLS AND PROPERTIES

In addition to the terms having defined meanings set forth in CSA Notice 51-324, 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, plus Enerplus' royalty interests in production or reserves. See " – Disclosure of Reserves and Production Information" above.

"gross" means:

(i)
in relation to Enerplus' interest in production or reserves, its working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of Enerplus;

(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 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

vi      ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM


(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

In this Annual Information Form, the following terms have the meaning assigned thereto in CSA Notice 51-324 and the COGE Handbook:

"Reserves" are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on: analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable, and shall be disclosed. Reserves may be divided into proved and probable categories according to the degree of certainty associated with the estimates.

"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% probability that the quantities actually recovered will equal or exceed the estimated Proved Reserves; and
at least a 50% 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 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

"Forecast prices and costs" means future prices and costs that are:

(i)
generally accepted as being a reasonable outlook of the future; and

(ii)
if, and only to the extent that, there are fixed or presently determinable future prices or costs to which Enerplus is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices or costs referred to in paragraph (i).

ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM      vii


"Constant prices and costs" means, unless expressly noted otherwise, prices and costs used in an estimate that are an unweighted average of the closing prices for the applicable commodity on the first day of each of the twelve months in 2009, held constant throughout the estimated lives of the properties to which the estimate applies.

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, 2009, which are available on the Fund's SEDAR profile at www.sedar.com, on EDGAR at www.sec.gov as part of the annual report on Form 40-F filed with the SEC together with this Annual Information Form, 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", "intend", "strategy", "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, drilling programs, development plans and other future expenditures;
supply and demand for oil, NGLs and natural gas;
Enerplus' business strategy including its asset and operational focus and transition from an income model to a hybrid growth and income model;
future acquisitions and dispositions;
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 and Enerplus' strategy for growth;
Enerplus' future operating and financial results;
future abandonment and reclamation costs;
the application of the SIFT Tax to the Fund, the potential conversion from a trust to a corporation and the potential timing and tax implications thereof;
the amount and tax treatment of future distributions and dividends paid by Enerplus;

viii      ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM


Enerplus' tax pools and the time at which Enerplus may incur certain income or other taxes;
treatment under governmental and other regulatory regimes and tax, environmental and other laws; and
future income tax laws and royalty regimes, including anticipated receipts under the Province of Alberta's drilling royalty credit program.

The forward-looking information and statements contained in Annual Information Form reflect several material factors and expectations and assumptions made by Enerplus including, without limitation, that: Enerplus will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures and requirements as needed; Enerplus' conduct and results of operations will be consistent with its expectations; Enerplus and its industry partners will have the ability to develop Enerplus' oil, gas and bitumen properties in the manner currently contemplated; current or, where applicable, proposed assumed industry conditions, laws and regulations will continue in effect or as anticipated as described herein; the estimates of Enerplus' reserves and resources volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects; there will be sufficient availability of services and labour to conduct Enerplus' operations as planned; and Enerplus' commodity price and other cost assumptions will generally be accurate. Enerplus believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable at this time but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

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 risks relating to:

volatility in market prices for oil, bitumen, NGLs and natural gas, including changes in supply or demand for those products;
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 royalty regimes and incentive programs relating to the oil and gas industry and income trusts;
unanticipated operating results including changes or fluctuations in oil, NGLs, natural gas and bitumen production levels;
changes in foreign currency exchange rates and interest rates;
changes in development plans by Enerplus or third party operators;
the ability of Enerplus to access required capital;
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 and reliance on industry partners;
uncertainties associated with estimating reserves and resources;
competition for, among other things, capital, acquisitions of reserves and resources, undeveloped lands, access to third party processing capacity and skilled personnel;
incorrect assessments of the value of acquisitions or the failure to complete dispositions;
constraints on, or the unavailability of, adequate pipeline and transportation capacity to deliver Enerplus' production to market;
Enerplus' success at the acquisition, exploitation and development of reserves and resources;
changes in general economic, market (including credit market) and business conditions in Canada, North America and worldwide; and
changes in environmental, regulatory or other legislation applicable to Enerplus' operations, and Enerplus' ability to comply with current and future environmental legislation and regulations and other laws and regulations.

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, 2009, which is available through the internet on Enerplus' SEDAR profile at www.sedar.com, on EDGAR at www.sec.gov as part of the annual report on Form 40-F filed with the SEC together with this Annual Information Form, 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.

ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM      ix


ENERPLUS RESOURCES FUND
Annual Information Form
For the year ended December 31, 2009

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 securities issued by its direct wholly-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 Computershare Trust Company of Canada located at Suite 600, 530 - 8th Avenue S.W., Calgary, Alberta T2P 3S8. The board of directors of EnerMark is responsible for the governance of Enerplus.

OPERATING SUBSIDIARIES

The Fund's Operating Subsidiaries acquire, exploit and operate crude oil and natural gas assets for the benefit of the Fund. See "Business of Enerplus", "Oil and Natural Gas Reserves" and "Supplemental Operational Information" for information regarding the operations and oil and natural gas reserves and contingent bitumen resources of Enerplus. As of December 31, 2009, the Fund's material Operating Subsidiaries were EnerMark, ERC, ECT, Enerplus USA and FET Operating Partnership.

Each of EnerMark and ERC are corporations organized under the Business Corporations Act (Alberta). ECT is a trust organized under the laws of Alberta, FET Operating Partnership is a general partnership 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, ECT, Enerplus USA and FET Operating Partnership are indirectly owned by the Fund.

ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM      1


ORGANIZATIONAL STRUCTURE

The simplified organizational structure of Enerplus as of December 31, 2009, 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.

GRAPHIC

2      ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM


General Development of Enerplus Resources Fund

GENERAL

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".

DEVELOPMENTS IN THE PAST THREE YEARS

Changes to Taxation of Income Trusts and Enerplus' Strategy Post-2010

On October 31, 2006, the Canadian Federal Minister of Finance proposed to subject certain types of income of publicly traded mutual fund trusts (a "SIFT Trust") to tax at rates comparable to the combined federal and provincial corporate tax rates (the "SIFT Tax"). This is accomplished by eliminating the trust's ability to deduct income distributions to unitholders, taxing the trust's income at corporate rates and treating distributions to unitholders as taxable dividends. The legislation governing the SIFT Tax (the "SIFT Provisions") became law on June 22, 2007. However, the SIFT Provisions are not expected to apply to the Fund prior to 2011 provided the Fund restricts itself to "normal growth" during the transitional period ending December 31, 2010. Any "undue expansion" during this transitional period may cause the SIFT Tax to apply to the Fund before January 1, 2011. For a SIFT Trust, "normal growth" includes equity growth within certain "safe harbour" limits, measured by reference to the market capitalization of the SIFT Trust as of the end of trading on October 31, 2006. Additional details of the parameters of "normal growth" include the following:

new equity for these purposes includes units and debt that is convertible into units (and may include other substitutes for equity if attempts are made to develop those);
replacing debt that was outstanding as of October 31, 2006 with new equity will not be considered growth for these purposes and will not affect the safe harbour; and
the exchange, for trust units, of exchangeable partnership units or exchangeable shares that were outstanding on October 31, 2006, will not be considered growth for those purposes and will not affect the safe harbour.

The combined market capitalization of the Fund and Focus as of the close of trading on October 31, 2006, having regard only to the issued and outstanding publicly traded trust units of each at such date, was approximately $9.1 billion. After deducting the value of new equity issued after October 31, 2006 and adding the value of new equity which could be issued to replace debt that was outstanding on October 31, 2006, Enerplus' aggregate remaining "safe harbour" growth limit is approximately $9.0 billion.

As a result of the enactment of the SIFT Provisions in 2007, the Fund's future income taxes disclosed in its financial statements were adjusted to include temporary differences between the accounting and tax bases of the Fund's assets and liabilities, as further described in Note 10 to the Fund's audited consolidated financial statements for the year ended December 31, 2009. In addition, the reported estimated net present value of future net revenues from Enerplus' oil and natural gas reserves on an "after-tax" basis now reflects the impact of the SIFT Tax on Enerplus' reserves. Enerplus anticipates converting to a dividend paying corporation on or about January 1, 2011. Enerplus intends to take advantage of the SIFT Trust conversion rules to significantly simplify its underlying organization structure at the same time Enerplus converts to a corporation. Enerplus currently anticipates that its corporate conversion will be achieved through a plan of arrangement effected under the Business Corporations Act (Alberta) which must be approved by the board of directors of EnerMark as well as the Fund's unitholders. The Fund intends to seek the required unitholder approval at a special meeting of unitholders to be held in December 2010. There is a risk that the Fund's unitholders may not approve the conversion to a corporation, however the Canadian government has legislated the SIFT Tax beginning in 2011 which effectively removes the benefits of remaining a trust.

Enerplus does not expect the conversion to a corporation to have a major impact on its underlying operating strategy or business affairs. Furthermore, although there is also a risk that conversion could create a taxable event for some of the Fund's unitholders, Enerplus currently does not anticipate that the conversion will create a taxable event for its unitholders. However, the final form, structure and steps involved in the conversion transaction have not yet been finalized and as a result Enerplus cannot guarantee that the conversion will not result in a taxable event for its securityholders. Enerplus currently does not expect to adjust its monthly cash dividends as a result of a conversion to a corporation. Going forward, the tax treatment of Enerplus' dividends or distributions may be different for its securityholders depending on their tax jurisdiction and whether they are holding their investment in a taxable account or tax-deferred account.

ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM      3


For additional information (including with respect to Enerplus' anticipated tax horizon), see "Business of Enerplus – Tax Horizon" and "Risk Factors – Risks Relating to Enerplus' Structure and Ownership of the Trust Units" in this Annual Information Form.

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 $61 million. This acquisition represented a modest addition to Enerplus' assets in the United States and established 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 is not required to expend any development capital or operating costs on these assets.

Acquisition of Kirby Oil Sands Partnership

On April 10, 2007, Enerplus acquired an undivided 90% interest in Kirby Oil Sands Partnership (including the managing partner's 0.01% partnership interest) for aggregate consideration of $182.8 million, payable by the issuance of 1,104,945 Trust Units at a price of $49.55 per Trust Unit, and the remaining $128.1 million in cash. On June 22, 2007, Enerplus acquired the remaining 10% interest in Kirby Oil Sands Partnership for cash consideration of $20.3 million, for a total purchase price of $203.1 million. As part of the transaction, Enerplus also acquired the petroleum and natural gas rights owned by the vendors in the lands to which the Kirby Lease relates, excluding the petroleum and natural gas rights in any section of land on which there is an existing petroleum or natural gas well, but only to the deepest formation penetrated by such well.

For additional information relating to the Kirby Project, see "Business of Enerplus – Enerplus' Resource Play Types – Oil Sands – Kirby Project".

Acquisition of Focus Energy Trust

On February 13, 2008, the Fund completed its acquisition of Focus pursuant to a plan of arrangement under the Business Corporations Act (Alberta). Pursuant to the arrangement, the Fund acquired all of the assets and assumed all of the liabilities of Focus, Focus unitholders received 0.425 of an Enerplus Trust Unit for each Focus trust unit, and all of the trust units of Focus were redeemed. Additionally, the Fund assumed the exchangeable limited partnership units of Focus Limited Partnership (a subsidiary of Focus, since renamed EELP), which became exchangeable into Trust Units of the Fund. The Fund issued an aggregate of 30,149,752 Trust Units to former Focus unitholders in the transaction, and as of December 31, 2009 Enerplus also had outstanding an aggregate of approximately 6,382,000 Exchangeable LP Units, exchangeable into approximately 2,712,000 Trust Units. Each EELP Exchangeable LP Unit is exchangeable for an Enerplus Trust Units on the basis of 0.425 of an Enerplus Trust Unit for each EELP Exchangeable LP Unit, and each EELP Exchangeable LP Unit has voting rights and entitlements to cash distributions in accordance with such exchange ratio. For a description of the EELP Exchangeable LP Units and the agreements relating thereto, see "Appendix G – Information Regarding Enerplus Exchangeable Limited Partnership" in this Annual Information Form.

Disposition of Joslyn Project

On July 31, 2008, Enerplus completed the sale of its 15% working interest in the Joslyn oil sands lease to Occidental Petroleum Corporation for net proceeds of approximately $502 million, after adjustments and transaction costs. The proceeds of the sale were used to reduce bank debt. The Joslyn project, located in northeastern Alberta, is an oil sands project operated by Total E&P Canada Ltd., a wholly-owned subsidiary of Total S.A. Enerplus had invested approximately $115 million on its 15% interest in the Joslyn project since its inception in 2002.

Acquisition of Interests in the Marcellus Properties

On September 1, 2009, Enerplus (through the Fund's indirect wholly-owned subsidiary, Enerplus USA) acquired an average 21.5% working interest in certain lands within the Marcellus shale natural gas play in the northeastern United States. Total consideration for the Marcellus Acquisition was approximately US$411.0 million (approximately Cdn$453.3 million). The transaction had an effective date of May 1, 2009. Under the terms of the transaction, Enerplus acquired an average 21.5% working interest through the acquisition of an undivided 30% interest in the Marcellus Vendors' average 72% working interest in the Marcellus Properties. The Marcellus Acquisition was completed in two

4      ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM



components, with one portion of the interests conveyed to Enerplus pursuant to the Marcellus Purchase Agreement and the remaining portion conveyed to Enerplus pursuant to the Marcellus JDA, as described in further detail below.

Pursuant to the Marcellus Purchase Agreement, Enerplus acquired an approximate 8.6% working interest in the Marcellus Properties (representing an undivided 12% interest in the Marcellus Vendors' average 72% working interest in the Marcellus Properties) for cash consideration of US$164.4 million (approximately Cdn$181.3 million), which was paid at closing. Enerplus and the Marcellus Vendors also entered into the Marcellus JDA on the closing date of the Marcellus Acquisition, under which Enerplus acquired an additional approximate 12.9% working interest in the Marcellus Properties (representing an undivided 18% interest in the Marcellus Vendors' average 72% working interest in the Marcellus Properties). Under the terms of the Marcellus JDA, the consideration of US$246.6 million (approximately Cdn$272.0 million) (the "Marcellus Carry Amount") for these additional working interests is to be paid over time as a "carry" and will represent 50% of the Marcellus Vendors' share of the future well drilling and completion costs on the Marcellus Properties until the Marcellus Carry Amount has been fully expended. As of December 31, 2009, the Marcellus Carry Amount was approximately US$237.3 million, after considering 2009 spending as well as final closing adjustments. Based on existing future drilling and completion plans, Enerplus anticipates the Marcellus Carry Amount will be spent by 2013. Since closing of the Marcellus Acquisition, Enerplus has spent approximately $5 million on the purchase of additional acreage and seismic data in the Marcellus play.

For a description of the Marcellus Properties and Enerplus' shale gas resource play, see "Business of Enerplus – Enerplus' Resource Play Types – Marcellus Shale Gas".

Additional Strategic Acquisitions and Dispositions

In 2009, Enerplus acquired additional Bakken land interests in southeast Saskatchewan and North Dakota for a purchase price of approximately $55.0 million, and disposed of $104.3 million of assets, almost all of which related to the sale of a non-core oil property in western Canada, with production of approximately 200 BOE/d.

In early 2010, Enerplus announced that it intends to dispose of approximately 14,000 BOE/d of non-core production that does not fit with Enerplus' strategy going forward. Enerplus intends to use the proceeds of such dispositions, if any, on strategic acquisitions and capital spending.

Strategic Positioning in the Current Economic and Industry Environment

2009 was a transition year for Enerplus as it continued to move from an income model to a growth and income-oriented model. Early in 2009, in response to the steep decline in commodity prices and the global credit crisis, Enerplus lowered its monthly cash distributions to $0.18 per Trust Unit and significantly reduced its development capital program. This was done to ensure it maintained a strong balance sheet to provide the financial flexibility and liquidity to pursue growth assets. Throughout 2010 Enerplus expects to continue to transition toward a dividend paying corporation that Enerplus believes will offer investors both growth and income. For additional information on Enerplus' business strategy, see "Business of Enerplus – Overview".

ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM      5


Business of Enerplus

OVERVIEW

As described above, 2009 was a transition year for Enerplus as it continued to move from an income model to a growth and income-oriented model. During this transition, Enerplus has been focused on delivering operational results, repositioning its asset base and adding key leadership and technical skills while balancing distributions and capital reinvestment with cash flows. Enerplus believes that it has made significant progress with respect to these strategies and that it is well positioned for success as the new growth plays begin to contribute to its results during 2010.

Enerplus is realigning its asset base to include not only mature income-oriented assets but also early stage, growth-oriented assets such as the Marcellus shale gas play in the U.S., Bakken/tight oil in both Canada and the U.S. and Deep Basin tight gas in Canada. Enerplus believes that it has started to accumulate a meaningful portfolio of growth prospects and expects to continue adding these types of properties to its portfolio. Enerplus also believes a greater concentration of assets will allow it to focus its activities on a fewer number of high impact properties to create the greatest value for its investors.

A key element of Enerplus' business strategy in 2009 was to add more early-stage resource plays to its portfolio both through acquisitions and organic development. Enerplus believes the addition of these types of plays will help to improve the profitability of its business and position it to show meaningful growth in both reserves and production. Enerplus acquired approximately 226,000 net acres of prospective land, the majority of which was in three key growth areas. The allocation of a portion of the capital budget to early stage resource plays rather than to producing properties negatively impacted year-over-year production growth. In 2009, Enerplus also added to its internal technical skill sets to improve its understanding and exploit its existing crude oil waterflood assets and other oil properties through the use of horizontal drilling, multi-stage fracture stimulation and enhanced oil recovery techniques. These mature properties have been on production for many years but Enerplus believes that they still have a significant amount of recoverable oil. By applying new techniques and technologies Enerplus believes it can improve the ultimate recovery from many of these fields, adding incremental reserves and production. In 2009, Enerplus managed its development capital spending and distributions within cash flow while meeting its production targets and advancing its growth strategy. Enerplus deferred its oil sands program in 2009 to focus its capital in its other growth plays.

Enerplus' acquisition and development activities are generally focused on "resource plays", which are typically large and aerially extensive accumulations of discovered oil, natural gas and bitumen with limited geological risk. Resource plays typically require many wells to develop the play over time. Resource plays generally exhibit lower production decline rates over the long term and a longer reserve life. Enerplus' six resource play types include: (i) Bakken/Tight Oil in Montana, North Dakota and southeast Saskatchewan; (ii) Marcellus Shale Gas in the northeastern United States; (iii) Tight Gas in northwestern Alberta and northeastern British Columbia; (iv) Crude Oil Waterfloods throughout western Canada; (v) Shallow Gas (which includes some shallow CBM properties) in southeast and central Alberta and southwest Saskatchewan; and (vi) Oil Sands in northeast Alberta. Additionally, Enerplus has interests in other conventional oil and natural gas properties throughout western Canada. Each of these play types and property interests is described in detail under "– Enerplus' Resource Play Types" below.

Unless otherwise noted, (i) all production and operational information in this Annual Information Form is presented as at or, where applicable, for the year ended, December 31, 2009, (ii) all production information represents Enerplus' company interest in production from these properties, which includes overriding royalty interests of Enerplus but is calculated before deduction of royalty interests owned by others, and (iii) all references to reserve volumes represent Enerplus' estimated company interest reserves (before deduction of royalties) contained in the McDaniel Report, NSAI Report or Haas Report, as applicable, using forecast prices and costs. See "Presentation of Enerplus' Oil and Gas Reserves, Resources and Production Information".

Enerplus' oil and natural gas property interests are located in western Canada in the provinces of Alberta, British Columbia, Saskatchewan and Manitoba, with minor landholdings in Ontario, and in the United States in the states of Montana, North Dakota, Pennsylvania, West Virginia, Maryland, Wyoming and Utah. Enerplus' major producing properties have related field production facilities and infrastructure to accommodate Enerplus' production. Production volumes for the year ended December 31, 2009 from Enerplus' properties consisted of approximately 41% crude oil and NGLs and 59% natural gas, on a BOE basis. Enerplus' 2009 average daily production was comprised of

6      ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM



32,984 bbls/d of crude oil, 4,157 bbls/d of NGLs and 326.6 MMcf/d of natural gas for a total of 91,569 BOE/d, a decrease of approximately 4% on a BOE basis when compared to 2008 average daily production of 34,581 bbls/d of crude oil, 4,627 bbls/d of NGLs and 338.9 MMcf/d of natural gas, for a total of 95,687 BOE/d. Enerplus exited 2009 with average daily production of approximately 85,400 BOE/d. Approximately 71% of Enerplus' 2009 production was operated by Enerplus and the remaining 29% was operated by industry partners. As at December 31, 2009, the oil and natural gas property interests held by Enerplus were estimated to contain Proved plus Probable Reserves of 110,568 Mbbls of light and medium crude oil, 46,778 Mbbls of heavy crude oil, 14,507 Mbbls of NGLs, 1,013,180 MMcf of natural gas and 24,890 MMcf of shale gas, for a total of 344,864 MBOE. See "Oil and Natural Gas Reserves".

The following table outlines Enerplus' reserves as at December 31, 2009 and its average daily production in 2009, in each case on a company interest basis, for five of Enerplus' six resource plays and its other conventional oil and natural gas properties. Enerplus' Oil Sands resource play did not have any production in 2009 and was not assigned any reserves at December 31, 2009.

Play Type   Proved
Reserves
  Probable
Reserves
  Proved Plus
Probable
Reserves
  Average Daily
Production
 

Bakken/Tight Oil   32.0 MMBOE   9.7 MMBOE   41.8 MMBOE   10,075 BOE/d  
Crude Oil Waterfloods   74.4 MMBOE   21.4 MMBOE   95.9 MMBOE   16,329 BOE/d  
Other Conventional Oil   31.5 MMBOE   10.6 MMBOE   42.2 MMBOE   10,777 BOE/d  

Total Oil   138.0 MMBOE   41.8 MMBOE   179.8 MMBOE   37,181 BOE/d  


Marcellus Shale Gas

 

8.1 Bcfe

 

16.8 Bcfe

 

24.9 Bcfe

 

514 Mcfe/d

 
Tight Gas   252.8 Bcfe   102.8 Bcfe   355.6 Bcfe   98,452 Mcfe/d  
Shallow Gas   272.7 Bcfe   95.1 Bcfe   367.8 Bcfe   140,008 Mcfe/d  
Other Conventional Gas   182.5 Bcfe   59.3 Bcfe   241.9 Bcfe   87,352 Mcfe/d  

Total Gas   716.2 Bcfe   274.0 Bcfe   990.2 Bcfe   326,326 Mcfe/d  

Total   257.4 MMBOE   87.5 MMBOE   344.9 MMBOE   91,569 BOE/d  

SUMMARY OF PRINCIPAL PRODUCTION LOCATIONS

During the year ended December 31, 2009, on a BOE basis, approximately 61% of Enerplus' production was derived from Alberta, 17% from Saskatchewan, 11% from Montana, 9% from British Columbia, 2% from Manitoba and minimal amounts from other jurisdictions (such as Pennsylvania, Utah, Wyoming and North Dakota). The following table describes the average daily production from Enerplus' principal producing properties and their primary resource play type during the year ended December 31, 2009. All properties listed in the table (other than "Other") are located in Alberta unless otherwise noted.

ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM      7


2009 Average Daily Production from Principal Properties

        Product
        Crude Oil
             
Property   Primary Play Type   Heavy   Light and Medium   NGLs   Natural Gas   Total  

 
        (bbls/d)   (bbls/d)   (bbls/d)   (Mcf/d)   (BOE/d)  
Shackleton, Saskatchewan   Shallow Gas         62,736   10,456  
Sleeping Giant, Montana, U.S.A.   Bakken/Tight Oil     8,046     9,963   9,707  
Tommy Lakes, British Columbia   Tight Gas     83   651   32,799   6,201  
Brooks   Other Conventional Oil   2,585     66   11,053   4,493  
Bantry   Shallow Gas     10     16,172   2,705  
Pembina 5 Way   Crude Oil Waterflood     2,015   126   2,411   2,543  
Giltedge   Crude Oil Waterflood   2,077       189   2,109  
Joarcam   Crude Oil Waterflood     1,333   62   4,181   2,092  
Medicine Hat Glauconitic "C" Unit   Crude Oil Waterflood   1,954       333   2,010  
Verger   Shallow Gas         11,900   1,983  
Elmworth   Tight Gas       350   8,149   1,708  
Pine Creek   Tight Gas     14   345   7,235   1,565  
Hanna Garden   Shallow Gas       4   9,081   1,518  
Burnt Timber   Tight Gas       8   7,946   1,332  
Medicine Hat South   Shallow Gas         7,636   1,273  
Chinchaga   Other Conventional Gas       16   7,502   1,266  
Hanlan-Robb   Other Conventional Gas       13   7,494   1,262  
Pouce Coupe   Tight Gas     277   41   5,324   1,205  
Virden, Manitoba   Crude Oil Waterflood     1,196       1,196  
Ansell   Tight Gas       70   5,893   1,052  
Mitsue   Crude Oil Waterflood     736   132   1,040   1,041  
Joffre   Shallow Gas         5,714   952  
Other   N/A   2,627   10,031   2,273   101,819   31,900  

 
TOTAL   N/A   9,243   23,741   4,157   326,570   91,569  

 

CAPITAL EXPENDITURES AND COSTS INCURRED

In 2009, Enerplus invested approximately $299 million through its capital program, net of $22 million in drilling royalty credits provided by the Province of Alberta, approximately 48% less than its capital program in 2008. Over 60% of Enerplus' capital spending in 2009 was invested in mature properties in its Crude Oil Waterflood, Shallow Gas, Tight Gas and Bakken/Tight Oil resource plays. Enerplus' investment in early stage growth projects grew 49% in 2009 to approximately $82 million, up from $55 million in 2008, and included approximately $30 million in undeveloped land and $30 million in drilling seven net assessment wells in various plays.

8      ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM


The following table outlines the capital expenditures made by Enerplus in 2009 with respect to each of its six resource plays and its other conventional oil and natural gas properties, net of $22 million in drilling royalty credits provided by the Province of Alberta.

Play Type   2009 Capital Spending  

    ($ millions)  
Bakken/Tight Oil   49  
Crude Oil Waterfloods   37  
Other Conventional Oil   16  
Oil Sands   15  

Total Oil   117  

Shallow Gas   61  
Tight Gas   95  
Marcellus Shale Gas   12  
Other Conventional Gas   14  

Total Gas   182  

Total   299  

In the financial year ended December 31, 2009, Enerplus made the following expenditures in the categories noted, as prescribed by NI 51-101:

    Property Acquisition Costs
         
    Proved   Unproved   Exploration
Costs
  Development
Costs
 

 
    ($ in millions)
Canada   2.6   59.7   29.5   194.5  
United States     487.1 (1) 5.0   41.0  

 
Total   2.6   546.8   34.5   235.5  

 

Note:

(1)
Includes actual expenditures of $238.8 million and remaining Marcellus Carry Amount obligations at December 31, 2009 of $248.3 million.

Enerplus expects its 2010 capital development spending to be approximately $425 million (net of $33 million in estimated Alberta drilling royalty credits) compared to its 2009 capital expenditures of approximately $299 million. Enerplus anticipates a 42% increase in development capital spending in 2010 versus 2009 given the improvement in crude oil prices and economic conditions, the strength of its balance sheet and increased opportunities associated with early stage growth-oriented assets. This increase in capital spending is primarily related to new opportunities in the Bakken/Tight Oil and the Marcellus Shale Gas resource plays. Enerplus anticipates that approximately $260 million of its 2010 capital budget will be spent on its Canadian assets and $165 million on its U.S. operations, with approximately 55% of its total spending directed at oil opportunities and the remainder on natural gas. Enerplus plans to direct its oil activities primarily at its Bakken properties in Canada and the U.S., as well as crude oil waterflood and conventional oil projects in western Canada. Enerplus' 2010 natural gas spending plans are primarily concentrated in the Marcellus Shale Gas play, drilling in the Canadian Deep Basin and shallow gas drilling in Alberta that is supported by government incentives. Enerplus' 2010 capital spending plans include approximately $125 million on drilling, seismic and minor land purchases associated with existing growth properties. The foregoing plans do not include any acquisition activity or large undeveloped land purchases as these are opportunistic and difficult to predict. Enerplus will review its 2010 capital investment plans regularly throughout the year in the context of prevailing economic conditions and potential acquisitions, and make adjustments as it deems necessary. Enerplus anticipates that its 2010 spending will be evenly distributed throughout the year given the nature and location of the spending.

ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM      9


Enerplus' currently planned 2010 capital expenditures for each of its resource plays and its other conventional oil and natural gas assets (net of an anticipated $33 million recovered through the Alberta drilling royalty incentive program) is as follows:

Play Type   2010 Planned
Capital Spending
 

    ($ millions)  
Bakken/Tight Oil   117  
Crude Oil Waterfloods   96  
Other Conventional Oil   18  
Oil Sands    

Total Oil   231  

Marcellus Shale Gas   80  
Tight Gas   56  
Shallow Gas   41  
Other Conventional Gas   17  

Total Gas   194  

Total   425  

EXPLORATION AND DEVELOPMENT ACTIVITIES

During 2009, Enerplus participated in the drilling of 429 gross oil and natural gas wells (313.0 net wells), including 138 net wells utilizing the Alberta drilling royalty credit program, with over a 99% net well success rate, along with 5 gross (0.7 net) service wells. The majority of Enerplus' drilling activity was in the shallow natural gas areas at Shackleton in Saskatchewan and Bantry, Verger and Hanna Garden in Alberta. Almost all of this shallow natural gas activity was in operated areas. Enerplus also had active operated drilling and facility programs in oil dominated areas such as Pembina and Giltedge in Alberta, Freda Lake in Saskatchewan, Virden in Manitoba, and Sleeping Giant in Montana. Non-operated drilling activity in 2009 was focused in deep tight gas areas at Brazeau, Ansell and Elmworth in Alberta, Bakken and tight oil areas at Taylorton in Saskatchewan and in North Dakota, and on Enerplus' U.S. Marcellus shale gas properties. The following table summarizes the number and type of wells that Enerplus drilled or participated in the drilling of for the year ended December 31, 2009, in each of Canada and the United States. Wells have been classified in accordance with the definitions of such terms in NI 51-101.

    Canada
  United States
 
    Development Wells
  Exploratory Wells
  Development Wells
  Exploratory Wells
 
Category of Well   Gross   Net   Gross   Net   Gross   Net   Gross   Net  

 
Crude oil wells   54   20.5   4   1.8   6   2.9      
Natural gas wells   335   272.7   16   10.9   12   3.1   1   1.0  
Service wells   5   0.7              
Dry and abandoned wells   1   0.1              

 
Total   395   294.0   20   12.7   18   6.0   1   1.0  

 

For a description of Enerplus planned 2010 development plans and the anticipated sources of funding those plans, see "– Capital Expenditures and Costs Incurred" above and "– Enerplus' Resource Play Types" below.

10      ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM


OIL AND NATURAL GAS WELLS AND UNPROVED PROPERTIES

The following table summarizes, as at December 31, 2009, Enerplus' interests in producing wells and in non-producing wells which were not producing but which may be capable of production, along with Enerplus' interests in unproved properties (as defined in NI 51-101). Although many wells produce both oil and natural gas, a well is categorized as an oil well or a natural gas well based upon the proportion of oil or natural gas production that constitutes the majority of production from that well.

    Producing Wells
  Non-Producing Wells
  Unproved
Properties
(thousands of acres)

    Oil
  Natural Gas
  Oil
  Natural Gas
         
    Gross   Net   Gross   Net   Gross   Net   Gross   Net   Gross   Net  

 
 
Alberta   3,383   1,358.9   7,171   3,561.4   1,049   457.1   786   325.9   923   378  
Saskatchewan   2,478   474.0   2,557   2,318.6   454   74.7   171   151.0   480   386  
British Columbia   213   27.4   315   178.1   49   8.1   90   33.1   287   123  
Manitoba   572   318.6       39   24.6       17   12  
Ontario                   34    
Montana   231   133.7       1   0.5       13   8  
North Dakota   2   2.0       2   0.6       33   21  
Pennsylvania       11   2.1       27   5.3   449   109  
Maryland                   21   6  
West Virginia                   35   10  
Utah   1   1.0               8   7  
Colorado               1   1.0   42   42  

 
 
Total   6,880   2,315.6   10,054   6,060.2   1,594   565.6   1,075   516.3   2,342   1,102  

 
 

Enerplus expects its rights to explore, develop and exploit on approximately 245,358 net acres of unproved properties to expire prior to December 31, 2010 in the ordinary course. Enerplus has no material work commitments on such properties and, where Enerplus determines appropriate, it can extend expiring leases by either making the necessary applications to extend or performing the necessary work.

ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM      11


ENERPLUS' RESOURCE PLAY TYPES

Outlined below is a description of each of Enerplus' six resource play types and its other conventional oil and natural gas properties.

Bakken/Tight Oil

GRAPHIC

Enerplus' Bakken/Tight Oil resource play includes properties in Montana, North Dakota and southeast Saskatchewan, including an approximate 70% average working interest in certain producing wells in the Sleeping Giant Bakken oil field in Richland County, Montana, which is one of Enerplus' largest producing properties. Existing production from this resource play is primarily from the Middle Bakken dolomite formation at a depth of approximately 10,000 feet and consists of light sweet crude oil (42o API) and some associated natural gas. Enerplus' Bakken/Tight Oil resource play represented approximately 11% of its 2009 average daily production on a BOE basis, with virtually all of this production coming from the Sleeping Giant project, and represented approximately 12% of Enerplus' Proved plus Probable Reserves as at December 31, 2009. These properties are predominantly operated by Enerplus.

In 2009, Enerplus added to its Bakken/Tight Oil portfolio and has now accumulated approximately 100 net sections of undeveloped Bakken land in both Canada and the U.S. In May 2009, Enerplus purchased a 25% working interest in 44 gross sections of prospective Bakken land in southeast Saskatchewan for $25 million, and followed with the purchase of a 50% working interest in approximately 34 gross sections of prospective Bakken land in North Dakota for US$27 million in October 2009.

In 2009, Enerplus' Bakken/Tight Oil capital spending was associated with ongoing development of its Sleeping Giant property in Montana and assessment drilling in its new areas. In late 2008, Enerplus suspended its drilling program at Sleeping Giant due to the significant drop in crude oil prices experienced at that time, but continued with its refrac program given the attractive economic returns (a "refrac" consists of the restimulation of a producing formation within an existing wellbore to enhance production and add new incremental reserves). As oil prices stabilized in the latter half of 2009, Enerplus resumed its drilling program and drilled an additional two wells by year-end along with a total of 19 refracs, for total spending of approximately $25 million. Enerplus also spent another $14 million primarily in assessment work in its new areas.

For 2010, Enerplus has currently allocated approximately $117 million in development capital to its Bakken/Tight Oil plays, with approximately $58 million to be invested in development activities at Sleeping Giant with another $54 million on assessment activities in its new areas. Enerplus plans to drill 31 net wells across the entire Bakken portfolio and expects to refrac 11 net wells at the Sleeping Giant property. Enerplus also plans to continue testing multi-well, simultaneous fracturing as well increasing the number of fracture stages per well at Sleeping Giant with up to six simultaneous fracs and up to 12 frac stages. In addition, Enerplus plans to test a number of higher stage fracture stimulation projects in its new areas.

12      ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM



Marcellus Shale Gas

GRAPHIC

Overview

In 2009, Enerplus made a strategic investment in the Marcellus shale gas fairway gaining entry into one of the largest shale gas resource plays in North America. Spanning six states in the northeast U.S., the Marcellus shale play covers an estimated 95,000 square miles. With its proximity to the large northeast U.S. natural gas market, Marcellus natural gas receives a premium price, which when combined with an attractive cost structure provides the potential for superior economic returns compared to other natural gas producing areas in North America. For information on the acquisition of the Marcellus Properties effective September 1, 2009, see "General Development of Enerplus Resources Fund – Developments in the Past Three Years – Acquisition of Interests in the Marcellus Properties". Between the initial acquisition in September 2009 and year-end, Enerplus added 10,000 net acres to its position and swapped certain acreage to consolidate its position. Enerplus continues to pursue other opportunities to increase and consolidate its acreage and potentially add an operated position in the area.

At December 31, 2009, Enerplus owned an average 23.6% non-operated working interest in approximately 534,000 acres of land. The majority of the land is concentrated in the northeast and southwest areas of Pennsylvania with additional acreage located in West Virginia and Maryland. Much of the acreage is contiguous and the majority of the leases allow extensions of the primary term (which have an average term of approximately five years) for an additional five years.

From the time that Enerplus entered the Marcellus shale gas play in September 2009 to year-end, it invested a total of $29 million on the play: $12 million representing Enerplus' share of capital, $12 million on the Marcellus Carry Amount which covers 50% of Chief's (Enerplus' partner) capital costs, and $5 million for the purchase of additional acreage and seismic data. Enerplus had anticipated that 15 wells would be drilled and seven wells would be completed by the end of 2009, however only 12 wells were drilled and five wells were completed due to scheduling of tie-ins and availability of services at the end of the year. Enerplus anticipates that substantial progress will be made in the

ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM      13



installation of gathering infrastructure in Lycoming County, Pennsylvania and Marshall County, West Virginia by early in the second quarter of 2010. Chief is focused on securing the required services to advance the completion programs. However, continued increases in industry activity could put additional pressure on costs and the timing of Enerplus' programs going forward.

At year end 2009, the Marcellus Properties had a total of 43 gross wells drilled with 11 wells on production, 22 wells waiting to be completed and 10 wells awaiting tie-in. Enerplus (through its operator, Chief) currently has four rigs working in the Marcellus play with a fifth rig expected early in the second quarter of 2010. Enerplus plans to drill and complete 12 gross wells and tie-in 8 additional wells during the first quarter of 2010. Daily production averaged 2.1 MMcfe/d net to Enerplus during the month of December. Based on current development plans, Enerplus expects its working interest share of gross production volumes to increase to approximately 100 MMcf/d of natural gas over the next four years.

Enerplus intends to spend approximately $80 million in development capital on its Marcellus Shale Gas resource play in 2010, plus an additional $64 million as part of the Marcellus Carry Amount.

The independent Haas Report has assigned 8.1 Bcfe of Proved Reserves and 24.9 Bcfe of Proved plus Probable Reserves to Enerplus' interest in the Marcellus Properties as of December 31, 2009. This represents an increase of over 200% from Enerplus' internal estimate of the Proved plus Probable Reserves effective July 2009 conducted in connection with the Marcellus Acquisition.

Haas has also conducted an independent assessment of the contingent resources attributable to Enerplus' interests in the Marcellus Properties and has provided a "best estimate" of natural gas contingent resources of approximately 2.1 Tcfe at December 31, 2009. This estimate assumes a land utilization rate of 55% and that the average well would produce approximately 3.4 Bcf per well, with the higher prospective areas producing approximately 5 Bcf per well. Enerplus expects recoveries to average approximately 30% with an average well density of 4 to 8 wells per section. Enerplus continues to see upside in the percentage of land that could be developed over time as delineation results continue to come in.

The contingent resource estimate for the Marcellus Properties is presented as the "best estimate" of the quantity that will actually be recovered, meaning that it is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate, and if probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the best estimate. The recovery and resource estimates provided herein are estimates only. Actual contingent resources (and any volumes that may be reclassified as reserves) and future production from such contingent resources may be greater than or less than the estimates provided herein.

There is no certainty that it will be commercially viable to produce, or 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 Marcellus Properties as "reserves" consist of: additional delineation drilling to establish economic productivity in the development areas, limitations to development based on adverse topography or other surface restrictions, the uncertainty regarding marketing and transportation of natural gas from development areas, the receipt of all required regulatory permits and approvals to develop the land, and access to confidential information of other operators in the Marcellus formation. Significant negative factors related to the estimate include: the pace of development, including drilling and infrastructure, is slower than the forecast, risk of adverse regulatory and tax changes, ongoing litigation related to minimum royalties payable to freehold landowners and other issues related to gas development in populated areas. There are a number of inherent risks and contingencies associated with the development of the acquired interests in the Marcellus Properties including commodity price fluctuations, project costs, Enerplus' ability to make the necessary capital expenditures to develop the properties, reliance on Enerplus' industry partners in project development, acquisitions, funding and provisions of services and those other risks and contingencies described above and that apply generally to oil and gas operations as described above and under "Risk Factors" in this Annual Information Form.

For additional information regarding the disclosure of contingent resources, see "Presentation of Enerplus' Oil and Gas Reserves, Resources and Production Information – Disclosure of Contingent Resources".

Description of the Marcellus JDA and Related Commercial Arrangements

Under the terms of the Marcellus JDA, until the full Marcellus Carry Amount has been spent by Enerplus, Chief has the sole right to propose the drilling and development of wells on the Marcellus Properties and Enerplus is required to participate in those operations (subject to certain exceptions, including limitations on wells drilled subsequent to an initial well being drilled in an area or when the Marcellus Vendors

14      ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM



have failed to conduct sufficient drilling activities as set out in the Marcellus JDA), and the operations on the Marcellus Properties will be conducted in accordance with a mutually agreed-upon development plan. Subject to certain cure provisions, if Enerplus defaults in its obligations to pay the required portion of the Marcellus Carry Amount on behalf of the Marcellus Vendors, in addition to other remedies available to the Marcellus Vendors, Enerplus will be required to reassign to the Marcellus Vendors all of its interests in the area where the proposed well was located, other than in respect of any existing wellbores located in the area in which Enerplus owns an interest. Additionally, in such circumstances, the Marcellus Vendors will have the right to suspend some or all of the Marcellus Vendors' obligations to Enerplus under the Marcellus JDA, including with respect to the sharing of certain information and the requirement to offer Enerplus its proportionate share of any subsequently-acquired interests pursuant to the Marcellus AMI Agreements, as defined and described below.

Following Enerplus' expenditure of the required Marcellus Carry Amount, either of Enerplus or Chief can propose well drilling and development plans and the other party may elect whether or not it will participate in such drilling and development. If a party elects not to participate, the provisions of the operating agreement with respect to the applicable area will govern the rights and remedies between the parties.

The Marcellus JDA also includes area of mutual interest provisions ("Marcellus AMI Agreements") with the Marcellus Vendors that will provide Enerplus the opportunity to partner with the Marcellus Vendors in any follow-on acquisitions or swaps in the Marcellus region. These Marcellus AMI Agreements will provide Enerplus with the opportunity to jointly acquire more land under the current ownership structure, as well as the potential to increase its working interest ownership on new lands and operate in certain new areas.

Enerplus has entered into long-term agreements for the gathering, dehydration and compression of Enerplus' share of production from the Marcellus Properties. These agreements are intended to provide Enerplus with cost certainty and direct ties to the northeast United States natural gas markets through connections with major interstate pipelines.

ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM      15


Tight Gas

GRAPHIC

Enerplus' Tight Gas resource play represented 18% of Enerplus' average daily production in 2009 and 17% of its Proved plus Probable Reserves as at December 31, 2009. Enerplus' highest producing tight natural gas properties in 2009 were its Tommy Lakes property in northern British Columbia and Pine Creek, Elmworth and Burnt Timber, all of which are located in Alberta. This play type includes multi-zone tight natural gas plays such as Cardium, Nikannassin, Montney, Bluesky, Nordegg and Halfway zones, as well as others.

Capital spending on Enerplus' Tight Gas properties increased to $95 million in 2009. At Tommy Lakes, Enerplus completed a 14 well program which was started in late 2008, spending approximately $30 million. Approximately $40 million was invested on acquiring prospective land and to perform seismic and assessment drilling activities in the Deep Basin region of Alberta and British Columbia where Enerplus now has approximately 50 net sections of undeveloped land targeting the Montney, Nordegg and Mannville formations.

Enerplus expects to reduce spending on this play in 2010 to approximately $56 million as it is not planning a development program at Tommy Lakes given the current outlook for natural gas prices. Enerplus has plans to drill a number of assessment wells along with some seismic work on its newly acquired lands targeting formations with potential for multi-frac horizontal well drilling.

16      ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM


Crude Oil Waterfloods

GRAPHIC

In a Crude Oil Waterflood, water is injected into the formation to supplement the original reservoir pressure and provide a drive mechanism to move additional oil to producing wells. Pressure maintenance and the production of oil from water injection can result in a production profile with more predictable and stable declines and higher recovery of reserves. Infill drilling and well/injector optimization are effective methods of enhancing reserve recovery even further.

In 2009, Enerplus' five largest waterflood producing properties were Pembina 5 Way, Joarcam, Giltedge, the Medicine Hat Glauconitic "C" Unit and Virden, all of which are located in Alberta with the exception of Virden, which is in Manitoba. Enerplus operates over 80% of its crude oil waterflood production. All of Enerplus' major waterflood areas have associated crude oil production installations for emulsion treating and injection or water disposal. In addition, the Joarcam property also has facilities for natural gas compression, dehydration and processing. Approximately 18% of Enerplus' production for the year ended December 31, 2009 and approximately 28% of Enerplus' Proved plus Probable Reserves as at December 31, 2009 were related to its crude oil waterflood assets.

Capital spending within Enerplus' Crude Oil Waterflood portfolio was largely focused at Freda Lake, Virden, Giltedge, Pembina 5 Way and Medicine Hat. Approximately $14 million was spent on drilling 11 net wells, including seven horizontal wells. Maintenance projects, including facility and pipeline integrity upgrades, were also a significant part of Enerplus' activities. In total, Enerplus invested $37 million in this resource play in 2009 and essentially maintained production levels year-over-year.

Assuming an improved outlook for crude oil prices relative to natural gas prices, Enerplus expects to significantly increase its capital spending in 2010 on its waterflood assets to approximately $96 million, net of estimated Alberta government drilling royalty credits of approximately $10 million. Enerplus plans to drill 38 net wells to optimize recovery at its Medicine Hat, Giltedge, Freda Lake, Cadogan and Virden properties. Enerplus also expects to advance its work on enhanced oil recovery pilots on its waterflood properties, which Enerplus anticipates will include at least one field pilot well to test the use of polymers to improve overall oil recovery.

ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM      17


Shallow Gas

GRAPHIC

Enerplus' Shallow Gas resource play, which includes certain CBM properties, has been a core development play for Enerplus since the late 1990s. The shallow natural gas formations in southern Alberta and southwest Saskatchewan consist of massive, tightly packed sandstone that covers an area of over 10,000 square kilometres. These zones are typically less than 800 metres in depth and upper Cretaceous in age, with most production coming from the Milk River, Medicine Hat, and Second White Specks producing zones.

The key to success in the Shallow Gas play involves executing large, multi-well development programs efficiently and subsequently managing the post-drilling operations of these low pressure wells in a cost-effective manner.

Shallow natural gas represented approximately 25% of Enerplus' average daily production volumes in 2009 and approximately 18% of Enerplus' Proved plus Probable Reserves as at December 31, 2009. Approximately 85% of Enerplus' shallow natural gas production is operated by Enerplus. In 2009, Enerplus' five largest shallow natural gas producing properties were the Shackleton field in southwest Saskatchewan and the Bantry, Verger, Hanna Garden, and Medicine Hat South properties in Alberta. All of these properties have associated pipeline infrastructure and compression facilities.

Enerplus invested $61 million in its shallow gas natural assets in 2009, net of approximately $17 million in Alberta drilling royalty credits, with most of its spending at the Shackleton field in Saskatchewan and at Bantry, Verger and Hanna Garden in Alberta. Due to weakening gas prices in the second quarter of 2009, Enerplus suspended its summer drilling program at Shackleton, preserving its drilling inventory pending higher sustainable natural gas prices, and with the implementation of the Alberta royalty drilling incentive program, Enerplus shifted its shallow natural gas drilling to Alberta. In total, Enerplus drilled 259 net shallow natural gas wells, including 120 net wells that attracted drilling royalty credits.

With the current natural gas price outlook, Enerplus' projected shallow natural gas spending for 2010 has been reduced to approximately $41 million, net of anticipated Alberta royalty drilling credits. Enerplus plans to drill approximately 156 net wells with a focus on infill drilling at Shackleton, Hanna Garden, Bantry and Verger. Enerplus believes these areas appear to offer the most attractive opportunities and allow Enerplus to take advantage of Alberta government drilling incentives of approximately $15 million. Enerplus anticipates that approximately 60% of its total wells drilled in 2010 will be shallow natural gas wells targeting the Milk River, Second White Specks and Medicine Hat formations.

18      ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM


Oil Sands

GRAPHIC

Enerplus' Oil Sands portfolio currently includes its operated SAGD Kirby Project and its joint venture with and equity ownership in Laricina. Enerplus invested $15 million in its oil sands portfolio in 2009, the majority of which was spent at the Kirby Project to complete its seismic program and the work associated with obtaining regulatory approvals, as described below.

Kirby Project:

Enerplus acquired the Kirby Lease in 2007 for an aggregate purchase price of $203.1 million. The Kirby Project is a 100% owned and operated SAGD project which Enerplus currently believes has potential production capacity, through staged development, of up to 50,000 bbls/d of bitumen. The Kirby Lease covers 43,360 gross acres (over 67 sections) of land in the Athabasca oil sands fairway near several other major SAGD development projects currently on production. While the Kirby Lease does not have current production or Proved or Probable Reserves attributed to it, the independent GLJ Oil Sands Resources Report effective December 31, 2009 indicates a "best estimate" of 497 MMbbls of aggregate contingent bitumen resources within the Kirby Lease, as outlined in the table below. Enerplus' development plan included developing the property in phases, with Phase 1 having production capability of 10,000 bbls/d of bitumen and Phases 2 and 3 each having incremental production capacity of 20,000 bbls/d of bitumen. Enerplus submitted the development application for Phase 1 to the regulatory authorities in September 2008 and continues to expect approval of its application for a 10,000 bbl/d in-situ oil sands project in 2010.

While Enerplus believes that the geologic characteristics, quality and potential of the Kirby Lease are attractive, Enerplus believes that the Kirby Project is not as compelling as other projects in its portfolio that have a shorter time frame to positive cash flow. Enerplus will continue to evaluate its options to maximize the value of this lease and expects only minimal spending on the Kirby Project in 2010.

GLJ, a private independent petroleum consulting firm based in Calgary, Alberta, has evaluated, estimated and subsequently prepared the GLJ Oil Sands Resources Report, which includes an estimate of the contingent bitumen resources associated with the Kirby Lease as of December 31, 2009, in accordance with the standards contained in the COGE Handbook. The GLJ Oil Sands Resources Report has provided the contingent resource estimates for the Kirby Lease on a bitumen basis rather than a synthetic crude oil basis as, at present, there are no definitive plans to provide an upgraded product. GLJ's best estimate represents an approximate 20% increase from its best estimate at December 31, 2008 and a 104% increase since Enerplus acquired the lease in 2007. The increase at year-end 2009 was generally as result of additional information gathered from Enerplus' seismic program conducted during 2009.

The contingent resource estimate for the Kirby Lease set forth below is presented as the "best estimate" of the quantity that will actually be recovered, meaning that it is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate, and if probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the best

ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM      19



estimate. The recovery and resource estimates provided herein are estimates only. Actual contingent resources (and any volumes that may be reclassified as reserves) and future production from such contingent resources may be greater than or less than the estimates provided herein.

    Best Estimate
of Contingent
Bitumen Resources
As of December 31, 2009
   

    (MMbbls )  
Wabiskaw D Formation   233    
McMurray North Formation   220    
McMurray South Formation   24    
Wabiskaw B Formation   20    

Total Kirby Lease Contingent Resource Estimate   497    

There is no certainty that it will be commercially viable to produce, or 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 Kirby Project as "reserves" consist of: further reservoir studies; delineation drilling; facility design; preparation of firm development plans including determination of the specific scope and timing of the project; requirement for regulatory approvals; the uncertainty regarding marketing plans for production from the subject areas; improved estimation of project costs; and Enerplus' internal approvals. There are a number of inherent risks and contingencies associated with the development of the Kirby Project, 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 development of the Kirby Project is subject to numerous risks".

For additional information regarding the disclosure of contingent resources, see "Presentation of Enerplus' Oil and Gas Reserves, Resources and Production Information – Disclosure of Contingent Resources".

Laricina:

In 2005, Enerplus formed a joint venture with Laricina, a private oil sands company focused on SAGD development in the Athabasca oil sands fairway that is led by the former Chief Executive Officer of Deer Creek Energy Limited. As part of this joint venture, Enerplus swapped a 1% working interest in the Joslyn oil sands lease for approximately 20% equity value in Laricina. As at December 31, 2009, Enerplus owned approximately 11% of the total outstanding equity of Laricina. Included in the swap was an area of mutual interest agreement which was designed to allow Enerplus and Laricina to jointly pursue additional in-situ oil sands ventures. Enerplus participated in four land acquisitions with Laricina since entering the agreement, which has now expired.

20      ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM


Other Conventional Oil and Gas Assets

In addition to the play types outlined above, Enerplus also owns other conventional oil and natural gas assets across western Canada. These assets include a diversified portfolio of smaller working interests in both operated and non-operated crude oil and natural gas projects and consist of various reservoir types. Development capital was reduced by approximately 71% in 2009 to $30 million, given Enerplus' desire to concentrate its capital spending and efforts in its core resource play areas. Enerplus has targeted a significant number of these properties for inclusion in its property divestment program. See "General Development of Enerplus Resources Fund – Developments in the Past Three Years – Additional Strategic Acquisitions and Dispositions".

Major conventional assets include the Brooks, Kingsford, Hayter, Enchant and Shorncliff properties in Alberta. Production from these other conventional oil and natural gas properties represented approximately 28% of Enerplus' average daily production in 2009 and approximately 24% of Enerplus' estimated total Proved plus Probable Reserves as of December 31, 2009.

Major facilities included in Enerplus' conventional oil and natural gas properties include: (i) a 100% interest in Brooks North and South oil batteries and water disposal facilities, (ii) a 22% interest in the oil emulsion treating and water disposal facility at Hayter, Alberta; (iii) a 100% interest in three oil facilities at Shorncliff, (iv) a 75% interest in the Colgate oil battery, (v) a 15% interest in the Sylvan Lake gas plant, and (vi) an 8% interest in the Hanlan-Robb gas plant.

ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM      21


QUARTERLY PRODUCTION HISTORY

The following table sets forth Enerplus' average daily production volumes, on a company interest basis, for each fiscal quarter in 2009 and for the entire year, separately for production in Canada and the United States, and in total.

    Year Ended December 31, 2009
Country and Product Type   First
Quarter
  Second
Quarter
  Third
Quarter
  Fourth
Quarter
  Total for
Year
 

 
Canada                      
Light and medium oil (bbls/d)   16,039   15,826   15,237   15,141   15,557  
Heavy oil (bbls/d)   9,342   9,395   9,109   9,130   9,243  

 
Total crude oil (bbls/d)   25,381   25,221   24,346   24,271   24,800  
Natural gas liquids (bbls/d)   4,059   4,420   3,912   4,238   4,157  

 
Total liquids (bbls/d)   29,440   29,641   28,258   28,509   28,957  
Natural gas (Mcf/d)   325,799   323,941   310,212   291,833   312,846  

 
Total Canada (BOE/d)   83,740   83,632   79,960   77,148   81,098  

 

United States

 

 

 

 

 

 

 

 

 

 

 
Light and medium crude oil (bbls/d)   9,046   8,494   7,872   7,319   8,184  
Natural gas (Mcf/d)   13,058   14,252   13,672   13,858   13,724  

 
Total United States (BOE/d)   11,222   10,869   10,151   9,629   10,471  

 

Total Enerplus

 

 

 

 

 

 

 

 

 

 

 
Light and medium oil (bbls/d)   25,085   24,320   23,109   22,460   23,741  
Heavy oil (bbls/d)   9,342   9,395   9,109   9,130   9,243  

 
Total crude oil (bbls/d)   34,427   33,715   32,218   31,590   32,984  
Natural gas liquids (bbls/d)   4,059   4,420   3,912   4,238   4,157  

 
Total liquids (bbls/d)   38,486   38,135   36,130   35,828   37,141  
Natural gas (Mcf/d)   338,857   338,193   323,884   305,691   326,570  

 
Total Enerplus (BOE/d)   94,962   94,501   90,111   86,777   91,569  

 

22      ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM


QUARTERLY NETBACK HISTORY

The following tables set forth Enerplus' average netbacks received for each fiscal quarter in 2009 and for the entire year, separately for production in Canada and the United States. Netbacks are calculated on the basis of prices received before the effects of commodity derivative instruments but after transportation costs, less related royalties and related production costs. For multiple product well types, production costs are entirely attributed to that well's principal product type. As a result, no production costs are attributed to Enerplus' NGLs production or United States natural gas production as those costs have been attributed to the applicable wells' principal product type.

    Year Ended December 31, 2009
Light and Medium Crude Oil ($ per bbl)     First
Quarter
    Second
Quarter
    Third
Quarter
    Fourth
Quarter
    Total for
Year
   

 
Canada                                  
Sales price(1)   $ 45.11   $ 60.41   $ 67.00   $ 68.41   $ 60.11    
Royalties     (6.50 )   (8.49 )   (11.84 )   (12.58 )   (9.81 )  
Production costs(2)     (19.84 )   (17.06 )   (18.87 )   (16.70 )   (18.12 )  

 
Netback   $ 18.77   $ 34.86   $ 36.29   $ 39.13   $ 32.18    

 

United States

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Sales price(1)   $ 40.04   $ 60.53   $ 65.47   $ 70.66   $ 58.41    
Royalties(3)     (9.00 )   (13.82 )   (15.12 )   (16.83 )   (13.50 )  
Production costs(2)     (4.71 )   (4.45 )   (4.37 )   (5.59 )   (4.76 )  

 
Netback   $ 26.33   $ 42.26   $ 45.98   $ 48.24   $ 40.15    

 

Total Enerplus

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Sales price(1)   $ 43.28   $ 60.45   $ 66.48   $ 69.14   $ 59.53    
Royalties(3)     (7.40 )   (10.35 )   (12.96 )   (13.96 )   (11.08 )  
Production costs(2)     (14.39 )   (12.65 )   (13.93 )   (13.08 )   (13.52 )  

 
Netback   $ 21.49   $ 37.45   $ 39.59   $ 42.10   $ 34.93    

 
 
    Year Ended December 31, 2009
Heavy Oil ($ per bbl)     First
Quarter
    Second
Quarter
    Third
Quarter
    Fourth
Quarter
    Total for
Year
   

 
Canada/Total Enerplus                                  
Sales price(1)   $ 40.09   $ 58.13   $ 61.04   $ 64.85   $ 56.03    
Royalties     (7.27 )   (10.68 )   (12.31 )   (13.25 )   (10.88 )  
Production costs(2)     (14.09 )   (15.06 )   (15.07 )   (12.78 )   (14.25 )  

 
Netback   $ 18.73   $ 32.39   $ 33.66   $ 38.82   $ 30.90    

 
 
    Year Ended December 31, 2009
Natural Gas Liquids ($ per bbl)     First
Quarter
    Second
Quarter
    Third
Quarter
    Fourth
Quarter
    Total for
Year
   

 
Canada/Total Enerplus                                  
Sales price(1)   $ 40.59   $ 35.47   $ 32.59   $ 56.96   $ 41.54    
Royalties     (11.30 )   (9.82 )   (9.16 )   (14.24 )   (11.16 )  
Production costs(2)                        

 
Netback   $ 29.29   $ 25.65   $ 23.43   $ 42.72   $ 30.38    

 

(continues on next page)

ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM      23


 
    Year Ended December 31, 2009
Natural Gas ($ per Mcf)     First
Quarter
    Second
Quarter
    Third
Quarter
    Fourth
Quarter
    Total for
Year
   

 
Canada                                  
Sales price(1)   $ 5.12   $ 3.45   $ 2.88   $ 3.95   $ 3.86    
Royalties     (0.92 )   (0.57 )   (0.13 )   (0.19 )   (0.46 )  
Production costs(2)     (1.36 )   (1.51 )   (1.44 )   (1.36 )   (1.42 )  

 
Netback   $ 2.84   $ 1.37   $ 1.31   $ 2.40   $ 1.98    

 

United States

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Sales price(1)   $ 5.38   $ 4.34   $ 4.55   $ 6.20   $ 5.11    
Royalties(3)     (1.10 )   (0.98 )   (0.96 )   (1.24 )   (1.07 )  
Production costs(2)                        

 
Netback   $ 4.28   $ 3.36   $ 3.59   $ 4.96   $ 4.04    

 

Total Enerplus

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Sales price(1)   $ 5.13   $ 3.49   $ 2.95   $ 4.06   $ 3.91    
Royalties(3)     (0.92 )   (0.58 )   (0.16 )   (0.24 )   (0.49 )  
Production costs(2)     (1.31 )   (1.45 )   (1.38 )   (1.30 )   (1.36 )  

 
Netback   $ 2.90   $ 1.46   $ 1.41   $ 2.52   $ 2.06    

 
 
    Year Ended December 31, 2009
Total Enerplus ($ per BOE)     First
Quarter
    Second
Quarter
    Third
Quarter
    Fourth
Quarter
    Total for
Year
   

 
Canada                                  
Sales price(1)   $ 34.80   $ 33.34   $ 32.48   $ 39.14   $ 34.89    
Royalties     (6.17 )   (5.52 )   (4.61 )   (5.55 )   (5.47 )  
Production costs(2)     (10.65 )   (10.77 )   (10.91 )   (9.93 )   (10.57 )  

 
Netback   $ 17.98   $ 17.05   $ 16.96   $ 23.66   $ 18.85    

 

United States

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Sales price(1)   $ 38.62   $ 53.04   $ 56.90   $ 62.63   $ 52.39    
Royalties(3)     (8.53 )   (12.09 )   (13.02 )   (14.58 )   (11.95 )  
Production costs(2)     (3.80 )   (3.47 )   (3.39 )   (4.25 )   (3.72 )  

 
Netback   $ 26.29   $ 37.48   $ 40.49   $ 43.80   $ 36.72    

 

Total Enerplus

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Sales price(1)   $ 35.24   $ 35.60   $ 35.23   $ 41.75   $ 36.89    
Royalties(3)     (6.43 )   (6.28 )   (5.56 )   (6.56 )   (6.21 )  
Production costs(2)     (9.84 )   (9.93 )   (10.07 )   (9.30 )   (9.79 )  

 
Netback   $ 18.97   $ 19.39   $ 19.60   $ 25.89   $ 20.89    

 

Notes:

(1)
Net of transportation costs but before the effects of commodity derivative instruments.
(2)
Production costs are costs incurred to operate and maintain wells and related equipment and facilities, including operating costs of support equipment used in oil and gas activities and other costs of operating and maintaining those wells and related equipment and facilities. Examples of production costs include items such as field staff labour costs, costs of materials, supplies and fuel consumed and supplies utilized in operating the wells and related equipment (such as power, chemicals and lease rentals), repairs and maintenance costs, property taxes, insurance costs, costs of workovers, net processing and treating fees, overhead fees, taxes (other than income, capital, withholding or U.S. state production taxes) and other costs.
(3)
Includes U.S. state production taxes.

24      ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM


ABANDONMENT AND RECLAMATION COSTS

In connection with its operations, Enerplus will incur abandonment and reclamation costs for surface leases, wells, facilities and pipelines. Enerplus budgets for and recognizes as a liability the estimated present value of the future asset retirement obligations associated with its property, plant and equipment. Enerplus estimates such costs through a model that incorporates data from Enerplus' operating history, industry sources and cost formulas used by Alberta's Energy Resources Conservation Board, together with other operating assumptions. Enerplus expects all of its net wells to incur these costs. Enerplus anticipates the total amount of such costs, net of estimated salvage value for such equipment, to be approximately $677 million on an undiscounted basis and $125 million discounted at 10%. The calculations of future net revenue under "Oil and Natural Gas Reserves" in this Annual Information Form exclude approximately $311 million on an undiscounted basis and $78 million discounted at 10% as these amounts represent costs for abandonment and reclamation of facilities and wells for which no reserves have been attributed. In the next three financial years, Enerplus anticipates that a total of approximately $49 million on an undiscounted basis and $43 million discounted at 10% will be incurred in respect of abandonment and reclamation costs.

TAX HORIZON

Canada

Under Enerplus' current structure, taxable income of the Canadian Operating Subsidiaries is transferred through interest, royalty and other distribution payments to the Fund, which in turn, allocates all of its taxable income to its unitholders. No material cash Canadian income taxes were paid by the Fund or its Canadian Operating Subsidiaries for the year ended December 31, 2009.

As described in further detail under "General Development of Enerplus Resources Fund – Developments in the Past Three Years – Changes to Taxation of Income Trusts and Enerplus' Strategy Post-2010" and "Risk Factors – Risks Relating to Enerplus' Structure and Ownership of the Trust Units", the Canadian federal government has implemented the SIFT Tax which will generally tax income trusts beginning in 2011 at the same effective tax rates as Canadian corporations. The most important variables that will determine the level of cash taxes incurred by Enerplus post-conversion will be the price of crude oil and natural gas, capital spending levels and the amount of tax pools and other deductions available.

Within the context of current commodity prices and capital spending plans, Enerplus does not expect to be taxable until 2013 to 2015. This future tax horizon will also fluctuate depending on the ultimate nature and timing of Enerplus' acquisitions and dispositions. Once it is taxable, Enerplus expects that its capital spending will help shelter taxes and would expect cash taxes to average approximately 15% of cash flow, which is not dissimilar to other oil and gas production companies. If crude oil and natural gas prices were to strengthen beyond the levels anticipated by the current forward market, Enerplus' tax pools would be utilized more quickly and it may experience higher than expected cash taxes or payment of such taxes in an earlier time period. However, Enerplus emphasizes that it is difficult to give guidance on future taxability as it operates within an industry that constantly changes given acquisitions, divestments, capital spending, distributions and overall commodity prices. See "Risk Factors – Risks Related to Enerplus' Business and Operations – Changes in tax or other laws may adversely affect unitholders."

United States

A total of $0.2 million of U.S. income related cash taxes were incurred with respect to U.S. operations during the year ended December 31, 2009. Enerplus' U.S. operations are subject to income taxes payable on the taxable income determined under U.S. income tax rules and regulations. As funds are repatriated back to Canada, withholding taxes as required by U.S. tax law would become payable. As a result, Enerplus' U.S. operations are expected to continue to incur U.S. income related cash taxes in the future.

For additional information, see Notes 1(h) and 10 to the Fund's audited financial statements for the year ended December 31, 2009 and the information under the heading "Taxes" in the Fund's management's discussion and analysis for the year ended December 31, 2009.

ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM      25


MARKETING ARRANGEMENTS AND FORWARD CONTRACTS

Crude Oil and NGLs

Enerplus' crude oil and NGLs production is marketed to a diverse portfolio of intermediaries and end users on 30 day continuously renewing contracts for crude oil and yearly contracts for NGLs whose terms fluctuate with monthly spot market prices. Enerplus received an average price (net of transportation costs but before the effects of commodity derivative instruments) of $59.53/bbl for its light and medium crude oil, $56.03/bbl for its heavy crude oil and $41.54/bbl for its NGLs for the year ended December 31, 2009, compared to $94.30/bbl for its light and medium crude oil, $80.15/bbl for its heavy crude oil and $68.93/bbl for its NGLs for the year ended December 31, 2008. Enerplus has a transportation commitment to deliver 1,698 bbls/d of Canadian production on the Plains Marketing Canada Joarcam Pipeline until March 31, 2010.

Natural Gas

In marketing its natural gas production Enerplus tries to achieve a mix of contracts and customers. Within its sales portfolio of aggregator, downstream and spot natural gas sales, Enerplus sold approximately 90% of its natural gas split evenly between the daily and monthly AECO market indices and 10% against monthly U.S.-based indices.

Enerplus' percentage of 2009 revenues attributable to natural gas (net of transportation costs but before the effects of commodity derivative instruments) was 38% compared to 45% in 2008. The average price received by Enerplus (net of transportation costs but before the effects of commodity derivative instruments) for its natural gas in 2009 was $3.91/Mcf compared to $8.17/Mcf in the year ended December 31, 2008.

Enerplus holds multiple contracts of various terms for transportation on the major gathering pipeline systems within the western provinces. The contracts comprise approximately 132 MMcf/d in Alberta, 32 MMcf/d in British Columbia and approximately 46 MMcf/d in Saskatchewan. As of December 31, 2009, Enerplus held 9 MMcf/d of firm transportation commitments on the Alliance Pipeline, in effect until October 31, 2015, under which Enerplus delivers natural gas into the U.S. Midwest area. The remainder of Enerplus' Canadian natural gas production is sold primarily in the provinces of Alberta, Saskatchewan and British Columbia at prevailing spot market prices. Enerplus has contracted gas gathering capacity for its Marcellus production of 4,500 MMbtu per day effective March 1, 2010, and increasing to 6,000 MMbtu per day on May 1, 2010.

Future Commitments and Forward Contracts

Enerplus may use various types of derivative financial instruments and fixed price physical sales contracts to manage the risk related to fluctuating commodity prices. Absent such hedging activities, all of the crude oil and NGLs and the majority of natural gas production of Enerplus is sold into the open market at prevailing market prices, which exposes Enerplus to the risks associated with commodity price fluctuations and foreign exchange rates. See "Risk Factors". Information regarding Enerplus' financial instruments is contained in Note 11 to the Fund's audited annual consolidated financial statements for the year ended December 31, 2009 and under the headings "Pricing" and "Price Risk Management" in the Fund's management's discussion and analysis for the year ended December 31, 2009, each of which is available through the internet on Enerplus' website at www.enerplus.com, on Enerplus' SEDAR profile at www.sedar.com and on EDGAR at www.sec.gov.

26      ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM


Oil and Natural Gas Reserves

SUMMARY OF RESERVES

All of Enerplus' reserves, including its U.S. reserves, have been evaluated in accordance with NI 51-101. McDaniel, an independent petroleum consulting firm 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 McDaniel. McDaniel has reviewed Enerplus' evaluation of these properties.

NSAI, independent petroleum consultants based in Dallas, Texas, have evaluated all of Enerplus' oil and natural gas reserves located in the western United States. Haas, independent petroleum consultants based in Dallas, Texas, have evaluated all of Enerplus' oil and natural gas reserves attributable to the Marcellus shale gas assets located in the northeastern United States. For consistency in Enerplus' reserves reporting, each of NSAI and Haas used McDaniel's forecast prices and inflation rates to prepare their reports. Enerplus used McDaniel's forecast exchange rates set forth below to convert U.S. dollar amounts in the NSAI Report and Haas Report to Canadian dollar amounts for presentation in this Annual Information Form.

The following sections and tables summarize, as at December 31, 2009, 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. All information relating to Canadian reserves is contained in the McDaniel Report and all information relating to United States reserves is aggregated from the NSAI Report and the Haas Report. 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.

For information relating to the changes in the volumes of Enerplus' reserves from December 31, 2008 to December 31, 2009, see "– Reconciliation of Reserves" below.

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. 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. The Canadian federal government has implemented the SIFT Tax which is designed to tax income trusts, such as Enerplus, at the same effective tax rates as Canadian corporations beginning with the 2011 tax year. The after-tax estimates of the net present value of future net revenue from Enerplus' reserves include the estimated impact of the SIFT Tax. For additional information, see "General Development of Enerplus Resources Fund – Developments in the Past Three Years", "Business of Enerplus – Tax Horizon", "Industry Conditions" and "Risk Factors" 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 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.

ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM      27


Summary of Oil and Gas Reserves
As of December 31, 2009
Forecast Prices and Costs

    OIL AND NATURAL GAS RESERVES
    Light & Medium Oil
  Heavy Oil
  Natural Gas Liquids
RESERVES CATEGORY   Company Interest   Gross   Net   Company Interest   Gross   Net   Company Interest   Gross   Net  

 
 
    (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)  
Proved Developed Producing                                      
  Canada   57,742   57,089   50,160   29,613   29,583   24,611   9,879   9,721   6,739  
  United States   21,062   21,002   17,518         76     76  

 
 
  Total   78,804   78,091   67,678   29,613   29,583   24,611   9,955   9,721   6,815  

 
 
Proved Developed Non-Producing                                      
  Canada   539   539   490   438   438   372   124   117   89  
  United States   1,276   1,276   1,064         4     4  

 
 
  Total   1,815   1,815   1,554   438   438   372   128   117   93  

 
 
Proved Undeveloped                                      
  Canada   2,772   2,765   2,461   4,380   4,380   3,560   630   630   486  
  United States   3,114   3,114   2,572         40     40  

 
 
  Total   5,886   5,879   5,033   4,380   4,380   3,560   670   630   526  

 
 
Total Proved                                      
  Canada   61,053   60,393   53,111   34,431   34,401   28,543   10,633   10,468   7,314  
  United States   25,452   25,392   21,154         120     120  

 
 
  Total   86,505   85,785   74,265   34,431   34,401   28,543   10,753   10,468   7,434  

 
 
Probable                                      
  Canada   16,776   16,551   13,940   12,347   12,338   9,924   3,718   3,659   2,592  
  United States   7,287   7,267   6,007         36     36  

 
 
  Total   24,063   23,818   19,947   12,347   12,338   9,924   3,754   3,659   2,628  

 
 
Total Proved Plus Probable                                      
  Canada   77,829   76,944   67,051   46,778   46,739   38,467   14,351   14,127   9,906  
  United States   32,739   32,659   27,161         156     156  

 
 
  Total   110,568   109,603   94,212   46,778   46,739   38,467   14,507   14,127   10,062  

 
 

(continues on next page)

28      ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM


 

Summary of Oil and Gas Reserves
As of December 31, 2009
Forecast Prices and Costs
(continued)

    OIL AND NATURAL GAS RESERVES
    Natural Gas
  Shale Gas
  Total
RESERVES CATEGORY   Company Interest   Gross   Net   Company Interest   Gross   Net   Company Interest   Gross   Net  

 
 
    (MMcf)   (MMcf)   (MMcf)   (MMcf)   (MMcf)   (MMcf)   (MBOE)   (MBOE)   (MBOE)  
Proved Developed Producing                                      
  Canada   624,588   608,201   522,773         201,332   197,761   168,638  
  United States   39,554   30,810   34,294   2,914   2,914   2,350   28,216   26,623   23,702  

 
 
  Total   664,142   639,011   557,067   2,914   2,914   2,350   229,548   224,384   192,340  

 
 
Proved Developed Non-Producing                                      
  Canada   13,444   13,297   11,236         3,341   3,309   2,824  
  United States   1,770   1,303   1,554   626   626   510   1,679   1,597   1,412  

 
 
  Total   15,214   14,600   12,790   626   626   510   5,020   4,906   4,236  

 
 
Proved Undeveloped                                      
  Canada   58,553   58,424   50,114         17,541   17,512   14,859  
  United States   8,125   3,574   7,497   4,587   4,587   3,709   5,273   4,475   4,479  

 
 
  Total   66,678   61,998   57,611   4,587   4,587   3,709   22,814   21,987   19,338  

 
 
Total Proved                                      
  Canada   696,585   679,922   584,123         222,214   218,582   186,321  
  United States   49,449   35,687   43,345   8,127   8,127   6,569   35,168   32,695   29,593  

 
 
  Total   746,034   715,609   627,468   8,127   8,127   6,569   257,382   251,277   215,914  

 
 
Probable                                      
  Canada   250,061   244,873   209,237         74,518   73,361   61,329  
  United States   17,085   13,137   14,770   16,763   16,763   13,545   12,964   12,249   10,762  

 
 
  Total   267,146   258,010   224,007   16,763   16,763   13,545   87,482   85,610   72,091  

 
 
Total Proved Plus Probable                                      
  Canada   946,646   924,795   793,360         296,732   291,943   247,650  
  United States   66,534   48,824   58,115   24,890   24,890   20,114   48,132   44,944   40,355  

 
 
  Total   1,013,180   973,619   851,475   24,890   24,890   20,114   344,864   336,887   288,005  

 
 

ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM      29


Summary of Net Present Value of Future Net Revenue
Attributable to Oil and Gas Reserves
As of December 31, 2009
Forecast Prices and Costs

    NET PRESENT VALUE OF FUTURE NET REVENUE DISCOUNTED AT (%/YEAR)
       
    Before Deducting Income Taxes
  After Deducting Income Taxes
    Unit  
RESERVES CATEGORY   0%   5%   10%   15%   20%   0%   5%   10%   15%   20%     Value(1)  

 
 
    (in $ millions)     ($/BOE)  
Proved developed producing                                                
  Canada   6,701   4,554   3,507   2,883   2,466   5,722   4,005   3,147   2,625   2,269   $ 20.80  
  United States   1,352   923   698   563   475   1,012   697   529   428   362   $ 29.45  

 
 
  Total   8,053   5,477   4,205   3,446   2,941   6,734   4,702   3,676   3,053   2,631   $ 21.86  

 
 
Proved developed non-producing                                                
  Canada   105   79   64   53   44   79   60   49   41   36   $ 22.66  
  United States   77   58   44   36   29   46   34   27   21   17   $ 31.16  

 
 
  Total   182   137   108   89   73   125   94   76   62   53   $ 25.50  

 
 
Proved undeveloped                                                
  Canada   380   242   160   107   71   224   129   74   40   17   $ 10.77  
  United States   175   107   71   48   34   124   80   55   40   30   $ 15.85  

 
 
  Total   555   349   231   155   105   348   209   129   80   47   $ 11.95  

 
 
Total Proved                                                
  Canada   7,186   4,875   3,731   3,043   2,581   6,025   4,194   3,270   2,706   2,322   $ 20.02  
  United States   1,604   1,088   813   647   538   1,182   811   611   489   409   $ 27.47  

 
 
  Total   8,790   5,963   4,544   3,690   3,119   7,207   5,005   3,881   3,195   2,731   $ 21.05  

 
 
Probable                                                
  Canada   2,990   1,449   877   601   444   2,200   1,068   646   443   327   $ 14.30  
  United States   705   326   190   129   95   445   205   112   73   52   $ 17.65  

 
 
  Total   3,695   1,775   1,067   730   539   2,645   1,273   758   516   379   $ 14.80  

 
 
Total Proved Plus Probable                                                
  Canada   10,176   6,324   4,608   3,644   3,025   8,225   5,262   3,916   3,149   2,649   $ 18.61  
  United States   2,309   1,414   1,003   776   633   1,627   1,016   723   562   461   $ 24.85  

 
 
  Total   12,485   7,738   5,611   4,420   3,658   9,852   6,278   4,639   3,711   3,110   $ 19.48  

 
 

Note:

(1)
Calculated using net present value of future net revenue of reserves before deducting income taxes, discounted at 10% per year. The unit values are based on net reserves volumes.

30      ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM


 

Summary of Oil and Gas Reserves
As of December 31, 2009
Constant Prices and Costs

    OIL AND NATURAL GAS RESERVES
    Light & Medium Oil
  Heavy Oil
  Natural Gas Liquids
RESERVES CATEGORY   Company Interest   Gross   Net   Company Interest   Gross   Net   Company Interest   Gross   Net  

 
 
    (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)  
Proved Developed Producing                                      
  Canada   54,802   54,151   50,576   29,025   28,995   24,917   8,683   8,517   5,944  
  United States   19,744   19,744   16,475         74     74  

 
 
  Total   74,546   73,895   67,051   29,025   28,995   24,917   8,757   8,517   6,018  

 
 
Proved Developed Non-Producing                                      
  Canada   527   527   488   428   428   379   110   102   80  
  United States   1,261   1,261   1,051         4     4  

 
 
  Total   1,788   1,788   1,539   428   428   379   114   102   84  

 
 
Proved Undeveloped                                      
  Canada   2,643   2,636   2,465   4,315   4,315   3,632   60   60   43  
  United States   2,751   2,751   2,271         36     36  

 
 
  Total   5,394   5,387   4,736   4,315   4,315   3,632   96   60   79  

 
 
Total Proved                                      
  Canada   57,972   57,314   53,529   33,768   33,738   28,928   8,853   8,679   6,067  
  United States   23,756   23,756   19,797         114     114  

 
 
  Total   81,728   81,070   73,326   33,768   33,738   28,928   8,967   8,679   6,181  

 
 
Probable                                      
  Canada   16,234   16,009   14,613   12,155   12,147   10,381   2,776   2,719   1,917  
  United States   6,876   6,876   5,718         27     27  

 
 
  Total   23,110   22,885   20,331   12,155   12,147   10,381   2,803   2,719   1,944  

 
 
Total Proved Plus Probable                                      
  Canada   74,206   73,323   68,142   45,923   45,885   39,309   11,629   11,398   7,984  
  United States   30,632   30,632   25,515         141     141  

 
 
  Total   104,838   103,955   93,657   45,923   45,885   39,309   11,770   11,398   8,125  

 
 

(continues on next page)

ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM      31


 

Summary of Oil and Gas Reserves
As of December 31, 2009
Constant Prices and Costs
(continued)

    OIL AND NATURAL GAS RESERVES
    Natural Gas
  Shale Gas
  Total
RESERVES CATEGORY   Company Interest   Gross   Net   Company Interest   Gross   Net   Company Interest   Gross   Net  

 
 
    (MMcf)   (MMcf)   (MMcf)   (MMcf)   (MMcf)   (MMcf)   (MBOE)   (MBOE)   (MBOE)  
Proved Developed Producing                                      
  Canada   529,262   513,001   461,263         180,721   177,164   158,314  
  United States   36,587   28,232   31,851   2,722   2,722   2,195   26,369   24,903   22,222  

 
 
  Total   565,849   541,233   493,114   2,722   2,722   2,195   207,090   202,067   180,536  

 
 
Proved Developed Non-Producing                                      
  Canada   9,018   8,871   7,483         2,568   2,535   2,194  
  United States   1,742   1,278   1,530   595   595   485   1,654   1,573   1,392  

 
 
  Total   10,760   10,149   9,013   595   595   485   4,222   4,108   3,586  

 
 
Proved Undeveloped                                      
  Canada   6,764   6,648   5,666         8,145   8,119   7,084  
  United States   7,157   3,009   6,627   3,757   3,757   3,037   4,607   3,879   3,919  

 
 
  Total   13,921   9,657   12,293   3,757   3,757   3,037   12,752   11,998   11,003  

 
 
Total Proved                                      
  Canada   545,044   528,520   474,412         191,434   187,818   167,592  
  United States   45,486   32,519   40,008   7,074   7,074   5,717   32,630   30,355   27,533  

 
 
  Total   590,530   561,039   514,420   7,074   7,074   5,717   224,064   218,173   195,125  

 
 
Probable                                      
  Canada   170,186   165,128   149,077         59,529   58,396   51,758  
  United States   14,856   11,962   12,824   16,151   16,151   13,048   12,071   11,562   10,056  

 
 
  Total   185,042   177,090   161,901   16,151   16,151   13,048   71,600   69,958   61,814  

 
 
Total Proved Plus Probable                                      
  Canada   715,230   693,648   623,489         250,963   246,214   219,350  
  United States   60,342   44,481   52,832   23,225   23,225   18,765   44,701   41,917   37,589  

 
 
  Total   775,572   738,129   676,321   23,225   23,225   18,765   295,664   288,131   256,939  

 
 

32      ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM


Summary of Net Present Value of Future Net Revenue
Attributable to Oil and Gas Reserves
As of December 31, 2009
Constant Prices and Costs

    NET PRESENT VALUE OF FUTURE NET REVENUE DISCOUNTED AT (%/YEAR)
       
    Before Deducting Income Taxes
  After Deducting Income Taxes
    Unit  
RESERVES CATEGORY   0%   5%   10%   15%   20%   0%   5%   10%   15%   20%     Value(1)  

 
 
    (in $ millions)     ($/BOE)  
Proved Developed Producing                                                
  Canada   2,863   2,111   1,706   1,449   1,269   2,709   2,024   1,651   1,412   1,243   $ 10.78  
  United States   671   506   408   343   298   541   411   332   280   244   $ 18.36  

 
 
  Total   3,534   2,617   2,114   1,792   1,567   3,250   2,435   1,983   1,692   1,487   $ 11.71  

 
 
Proved Developed Non-Producing                                                
  Canada   48   39   31   27   24   43   35   28   23   21   $ 14.12  
  United States   41   31   24   20   16   29   21   16   13   10   $ 17.25  

 
 
  Total   89   70   55   47   40   72   56   44   36   31   $ 15.34  

 
 
Proved Undeveloped                                                
  Canada   158   101   68   46   31   116   71   45   29   17   $ 9.60  
  United States   47   24   10   1   (5 ) 37   20   9   2   (4 ) $ 2.55  

 
 
  Total   205   125   78   47   26   153   91   54   31   13   $ 7.09  

 
 
Total Proved                                                
  Canada   3,069   2,251   1,805   1,522   1,324   2,868   2,130   1,724   1,464   1,281   $ 10.77  
  United States   759   561   442   364   309   607   452   357   295   250   $ 16.05  

 
 
  Total   3,828   2,812   2,247   1,886   1,633   3,475   2,582   2,081   1,759   1,531   $ 11.52  

 
 
Probable                                                
  Canada   1,116   602   392   282   216   875   493   328   240   185   $ 7.57  
  United States   254   137   86   60   45   179   97   58   39   29   $ 8.55  

 
 
  Total   1,370   739   478   342   261   1,054   590   386   279   214   $ 7.73  

 
 
Total Proved Plus Probable                                                
  Canada   4,185   2,853   2,197   1,804   1,540   3,743   2,623   2,052   1,704   1,466   $ 10.02  
  United States   1,013   698   528   424   354   786   549   415   334   279   $ 14.05  

 
 
  Total   5,198   3,551   2,725   2,228   1,894   4,529   3,172   2,467   2,038   1,745   $ 10.61  

 
 

Note:

(1)
Calculated using net present value of future net revenue of reserves before deducting income taxes, discounted at 10% per year. The unit values are based on net reserves volumes.

ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM      33


FORECAST PRICES AND COSTS

The forecast price and cost case assumes no legislative or regulatory amendments, and includes the effects of inflation. The estimated future net revenue to be derived from the production of the reserves includes the following price forecasts supplied by McDaniel as of January 1, 2010 (and utilized by NSAI and Haas for consistency in Enerplus' reserves reporting) and the following inflation and exchange rate assumptions:

    CRUDE OIL
  NATURAL GAS
  NATURAL GAS LIQUIDS
         
    WTI   Edmonton   Hardisty   Cromer   30 day   Henry   Edmonton Par Price
         
Year   Cushing
Oklahoma
  Par Price
40° API(1)
  Heavy
12° API
  Medium
29.3° API
  spot
@ AECO
  Hub
Price
  Propanes   Butanes   Pentanes
Plus
  Inflation
Rate
  Exchange
Rate
 

 
 
 
    ($US/bbl)   ($Cdn/bbl)   ($Cdn/bbl)   ($Cdn/bbl)   ($Cdn/MMbtu)   ($US/MMbtu)   ($Cdn/bbl)   ($Cdn/bbl)   ($Cdn/bbl)   (%/year)   ($US/$Cdn)  
2010   80.00   83.20   68.10   76.50   6.05   6.05   46.40   64.00   85.20   2.0   0.95  
2011   83.60   87.00   67.60   79.10   6.75   6.90   49.50   66.90   89.00   2.0   0.95  
2012   87.40   91.00   68.00   81.80   7.15   7.30   52.00   70.00   93.80   2.0   0.95  
2013   91.30   95.00   68.10   85.40   7.45   7.70   54.30   73.10   97.10   2.0   0.95  
2014   95.30   99.20   71.10   89.20   7.80   8.15   56.70   76.30   101.40   2.0   0.95  
Thereafter     (2)   (2)   (2)   (2)   (2)   (2)   (2)   (2)   (2) 2.0   0.95  

 
 
 

Notes:

(1)
Edmonton refinery postings for 40o API, 0.4% sulphur content crude oil.
(2)
Escalation is approximately 4% per year to 2015, and then approximately 2% per year thereafter.

In 2009, Enerplus received a weighted average price (net of transportation costs but before hedging) of $56.03/bbl for heavy crude oil, $59.53/bbl for light and medium crude oil, $41.54/bbl for NGLs and $3.91/Mcf for natural gas.

CONSTANT PRICES AND COSTS

The constant price and cost case is based upon an unweighted average of the closing prices for the applicable commodity on the first day of the twelve months preceding the company's fiscal year-end as at December 31, 2009, held constant throughout the estimated lives of the properties to which the estimate applies, and assumes the continuance of operating costs projected for 2010 and the continuance of current laws and regulations. Product prices have not been escalated nor have operating and capital costs been increased on an inflationary basis. The future net revenue to be received from the production of the reserves was based on the following constant prices determined as at December 31, 2009 and the following exchange rate assumptions:

    CRUDE OIL
  NATURAL GAS
  NATURAL GAS LIQUIDS
         
    WTI   Edmonton   Hardisty   Cromer   30 day   Henry   Edmonton Par Price
         
Year   Cushing
Oklahoma
  Par Price
40° API(1)
  Heavy
12° API
  Medium
29.3° API
  spot
@ AECO
  Hub
Price
  Propanes   Butanes   Pentanes
Plus
  Inflation
Rate
  Exchange
Rate
 

 
 
 
    ($US/bbl)   ($Cdn/bbl)   ($Cdn/bbl)   ($Cdn/bbl)   ($Cdn/MMbtu)   ($US/MMbtu)   ($Cdn/bbl)   ($Cdn/bbl)   ($Cdn/bbl)   (%/year)   ($US/$Cdn)  
Constant   61.18   65.21   59.38   62.02   3.77   3.82   37.36   46.52   68.71     0.869  

 
 
 

Note:

(1)
Edmonton refinery postings for 40o API, 0.4% sulphur content crude oil.

34      ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM


UNDISCOUNTED FUTURE NET REVENUE BY RESERVES CATEGORY

The undiscounted total future net revenue by reserves category as of December 31, 2009, using forecast prices and costs, is set forth below (columns or rows may not add due to rounding):

Reserves Category   Revenue   Royalties
and
Production
Taxes
  Operating
Costs
  Develop-
ment
Costs
  Abandon-
ment
and
Reclamation
Costs
  Future Net
Revenue
Before
Income
Taxes
  Income
Taxes
  Future Net
Revenue
After
Income
Taxes
 

    (in $ millions)
Proved Reserves                                  
  Canada   15,809   2,499   5,257   582   286   7,186   1,161   6,025  
  United States   2,933   757   464   79   28   1,604   422   1,182  

  Total   18,743   3,255   5,722   661   314   8,790   1,583   7,207  

Proved Plus Probable Reserves                                  
  Canada   22,047   3,616   7,183   739   332   10,176   1,951   8,225  
  United States   4,207   1,086   676   103   34   2,309   682   1,627  

  Total   26,254   4,701   7,859   842   366   12,485   2,633   9,852  

NET PRESENT VALUE OF FUTURE NET REVENUE BY RESERVES CATEGORY

The net present value of future net revenue before income taxes by reserves category and production group as of December 31, 2009, using forecast prices and costs and discounted at 10% per year, is set forth below:

Reserves Category   Production Group   Net Present Value of
Future Net Revenue
Before Income Taxes
(Discounted at 10%/year)
  Unit Value(3)  

        (in $ millions)   ($/Bbl/$/Mcf)  
Canada              
Proved Reserves   Light and Medium Crude Oil(1)   1,389   $26.30/bbl  
    Heavy Oil(1)   762   $26.71/bbl  
    Natural Gas(2)   1,580   $2.96/Mcf  
    Shale Gas(2)      
   
     
    Total   3,731      

Proved Plus Probable Reserves   Light and Medium Crude Oil(1)   1,659   $24.88/bbl  
    Heavy Oil(1)   938   $24.40/bbl  
    Natural Gas(2)   2,011   $2.76/Mcf  
    Shale Gas(2)      
   
     
    Total   4,608      

United States              
Proved Reserves   Light and Medium Crude Oil(1)   740   $29.09/bbl  
    Heavy Oil(1)      
    Natural Gas(2)   58   $4.21/Mcf  
    Shale Gas(2)   15   $1.86/Mcf  
   
     
    Total   813      

Proved Plus Probable Reserves   Light and Medium Crude Oil(1)   883   $26.97/bbl  
    Heavy Oil(1)      
    Natural Gas(2)   71   $4.05/Mcf  
    Shale Gas(2)   49   $1.96/Mcf  
   
     
    Total   1,003      

Total Enerplus              
Proved Reserves   Light and Medium Crude Oil(1)   2,129   $27.21/bbl  
    Heavy Oil(1)   762   $26.71/bbl  
    Natural Gas(2)   1,638   $2.99/Mcf  
    Shale Gas(2)   15   $1.86/Mcf  
   
     
    Total   4,544      

Proved Plus Probable Reserves   Light and Medium Crude Oil(1)   2,542   $25.57/bbl  
    Heavy Oil(1)   938   $24.40/bbl  
    Natural Gas(2)   2,082   $2.79/Mcf  
    Shale Gas(2)   49   $1.96/Mcf  
   
     
    Total   5,611      

Notes:

(1)
Including net present value of solution gas and other by-products.
(2)
Including net present value of by-products, but excluding solution gas and by-products from oil wells.
(3)
Calculated using net oil or net gas reserves and forecast price and cost assumptions.

ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM      35


ESTIMATED PRODUCTION FOR GROSS RESERVES ESTIMATES

The volume of production estimated for 2010 in preparing the estimates of gross Proved Reserves and gross Probable Reserves is set forth below. Canadian production has been estimated by McDaniel and U.S. production has been estimated by NSAI and Haas. Columns may not add due to rounding.

    Gross Proved Reserves
    Canada
  United States
Product Type   Estimated 2010
Aggregate
Production
  Estimated 2010
Average Daily
Production
  Estimated 2010
Aggregate
Production
  Estimated 2010
Average Daily
Production
 

 
Crude Oil                  
  Light and Medium Crude Oil   5,091 Mbbls   13,948 bbls/d   2,876 Mbbls   7,878 bbls/d  
  Heavy Oil   3,531 Mbbls   9,674 bbls/d      

 
Total Crude Oil   8,622 Mbbls   23,622 bbls/d   2,876 Mbbls   7,878 bbls/d  
Natural Gas Liquids   1,301 Mbbls   3,565 bbls/d   13 Mbbls   34 bbls/d  

 
Total Liquids   9,924 Mbbls   27,188 bbls/d   2,888 Mbbls   7,912 bbls/d  
Natural Gas   94,599 MMcf   259,176 Mcf/d   4,867 MMcf   13,335 Mcf/d  
Shale Gas       616 MMcf   1,689 Mcf/d  

 
Total   25,690 MBOE   70,384 BOE/d   3,802 MBOE   10,416 BOE/d  

 
 
    Gross Probable Reserves
    Canada
  United States
Product Type   Estimated 2010
Aggregate
Production
  Estimated 2010
Average Daily
Production
  Estimated 2010
Aggregate
Production
  Estimated 2010
Average Daily
Production
 

 
Crude Oil                  
  Light and Medium Crude Oil   167 Mbbls   459 bbls/d   228 Mbbls   626 bbls/d  
  Heavy Oil   166 Mbbls   456 bbls/d      

 
Total Crude Oil   334 Mbbls   914 bbls/d   228 Mbbls   626 bbls/d  
Natural Gas Liquids   61 Mbbls   165 bbls/d     1 bbl/d  

 
Total Liquids   393 Mbbls   1,078 bbls/d   228 Mbbls   627 bbls/d  
Natural Gas   3,985 MMcf   10,917 Mcf/d   324 MMcf   886 Mcf/d  
Shale Gas       801 MMcf   2,193 Mcf/d  

 
Total   1,058 MBOE   2,898 BOE/d   416 MBOE   1,140 BOE/d  

 

FUTURE DEVELOPMENT COSTS

The amount of development costs deducted in the estimation of net present value of future net revenue is set forth below. Enerplus intends to fund its development activities through internally generated cash flow, as well as through debt or the issuance of Trust Units where required. Enerplus does not anticipate that the cost of obtaining the funds required for these development activities will have a material effect on Enerplus' disclosed oil and gas reserves or future net revenue attributable to those reserves. For additional information, see "Business of Enerplus – Capital Expenditures and Costs Incurred" and "Business of Enerplus – Exploration and Development Activities":

    CANADA
  UNITED STATES
    Proved Reserves
  Proved Plus
Probable Reserves

  Proved Reserves
  Proved Plus
Probable Reserves

Year   Undiscounted   Discounted
at 10%/year
  Undiscounted   Discounted
at 10%/year
  Undiscounted   Discounted
at 10%/year
  Undiscounted   Discounted
at 10%/year
 

 
    (in $ millions)
2010   150   143   168   160   69   66   83   79  
2011   142   123   192   166   3   3   3   3  
2012   113   89   138   109   7   5   7   5  
2013   50   36   107   77       9   6  
2014   25   16   33   22       1   1  
Remainder   102   42   101   40          

 
Total   582   449   739   574   79   74   103   94  

 

36      ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM


RECONCILIATION OF RESERVES

Overview

Enerplus experienced negative reserve revisions in 2009. The negative reserve revisions were associated with both Enerplus' Proved Reserves and Probable Reserves and resulted from the removal of undeveloped drilling locations, changes in evaluation methodology, reservoir performance and the decline in natural gas prices. In total, approximately 0.37 Tcf of natural gas reserves, representing approximately 25% of Enerplus' total 2008 year-end natural gas bookings, and approximately 6 MMBOE of crude oil and NGLs reserves, representing approximately 3% of Enerplus' total 2008 year-end crude oil and NGLs reserves, were impacted, representing approximately 16% of Enerplus' total Proved plus Probable Reserves.

Approximately 42% of the revisions were attributable to the removal of approximately 1,400 undeveloped drilling locations and a reduction in the reserves attributable to the remaining undeveloped drilling locations. The majority of these revisions were in Enerplus' shallow natural gas resource properties. In total, approximately 0.15 Tcfe of reserves associated with Enerplus' natural gas properties and 3 MMBOE of reserves associated with Enerplus' crude oil properties were impacted by this factor. After revisions, Enerplus now has approximately 1,000 future drilling locations in its reserve evaluations with close to 700 of those being shallow natural gas locations. Although Enerplus has not booked many Marcellus Shale Gas or Canadian Tight Gas drilling locations, the significant reduction in shallow natural gas locations was driven by Enerplus' belief that it will direct a majority of its spending toward the higher impact Marcellus and Canadian tight gas plays as well as crude oil properties. Enerplus' inventory of undeveloped oil drilling locations remains at approximately 200 locations, with only limited locations related to its Bakken/Tight Oil growth areas at this time.

Methodology changes used by Enerplus' new independent Canadian conventional reserve evaluators, McDaniel (who replaced Sproule Associates Limited in August 2009), accounted for approximately 27% of the reduction, or approximately 0.10 Tcfe from natural gas properties (primarily shallow natural gas) and 1.6 MMBOE from crude oil properties. The methodology changes included a different assessment of final economic producing rates and decline factors than were previously used. Maintenance capital requirements were also increased to include ten additional years (increased from 10 to 20 years) and an increased amount per year, resulting in approximately $140 million ($70 million of net present value discounted at 10%) of additional future development capital requirements.

Performance issues accounted for 28% of the reduction, consisting of approximately 0.10 Tcfe associated primarily with Enerplus' shallow natural gas and 2.2 MMBOE associated with Enerplus' crude oil properties. Lower than anticipated infill well performance and increased interference between wells has steepened the decline of Enerplus' shallow natural gas properties.

The following tables reconcile Enerplus' oil and natural gas reserves (on both a company interest and a gross reserves basis) from December 31, 2008 to December 31, 2009, by country and in total, using forecast prices and costs. Certain columns may not add due to rounding.

Reconciliation of Company Interest Reserves


Canadian Oil and Gas Reserves

CANADA
  Light & Medium Oil
  Heavy Oil
  Natural Gas Liquids
Factors   Proved   Probable   Proved
Plus
Probable
  Proved   Probable   Proved
Plus
Probable
  Proved   Probable   Proved
Plus
Probable
   

 
 
    (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)    
December 31, 2008   68,425   19,274   87,699   33,139   12,790   45,929   12,939   4,714   17,653    
Acquisitions   413   170   583         5   3   8    
Divestments   (1,090 ) (279 ) (1,369 )       (42 ) (11 ) (53 )  
Discoveries                      
Extensions and Improved Recovery   921   269   1,190   947   831   1,778   102   87   189    
Economic Factors   197   (2 ) 195   (18 ) 3   (15 ) (73 ) (19 ) (92 )  
Technical Revisions   (2,135 ) (2,656 ) (4,791 ) 3,737   (1,277 ) 2,460   (781 ) (1,056 ) (1,837 )  
Production   (5,678 )   (5,678 ) (3,374 )   (3,374 ) (1,517 )   (1,517 )  

 
 
December 31, 2009   61,053   16,776   77,829   34,431   12,347   46,778   10,633   3,718   14,351    

 
 

(continues on next page)

ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM      37


 

Reconciliation of Company Interest Reserves (continued)

CANADA
  Associated and
Non-Associated Gas
(Natural Gas)

  Shale Gas
  Total
Factors   Proved   Probable   Proved
Plus
Probable
  Proved   Probable   Proved
Plus
Probable
  Proved   Probable   Proved
Plus
Probable
   

 
 
    (MMcf)   (MMcf)   (MMcf)   (MMcf)   (MMcf)   (MMcf)   (MBOE)   (MBOE)   (MBOE)    
December 31, 2008   1,025,866   397,651   1,423,517         285,481   103,053   388,534    
Acquisitions   276   171   447         465   201   666    
Divestments   (755 ) (130 ) (885 )       (1,257 ) (312 ) (1,569 )  
Discoveries   358   89   447         61   13   74    
Extensions and Improved Recovery   5,941   7,918   13,859         2,959   2,508   5,467    
Economic Factors   (10,072 ) (4,395 ) (14,467 )       (1,572 ) (751 ) (2,323 )  
Technical Revisions   (210,840 ) (151,243 ) (362,083 )       (34,322 ) (30,194 ) (64,516 )  
Production   (114,189 )   (114,189 )       (29,601 )   (29,601 )  

 
 
December 31, 2009   696,585   250,061   946,646         222,214   74,518   296,732    

 
 
 


United States Oil and Gas Reserves

UNITED STATES
  Light & Medium Oil
  Heavy Oil
  Natural Gas Liquids
Factors   Proved   Probable   Proved
Plus
Probable
  Proved   Probable   Proved
Plus
Probable
  Proved   Probable   Proved
Plus
Probable
   

 
 
    (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)    
December 31, 2008   26,128   6,867   32,995         113   51   164    
Acquisitions                      
Divestments                      
Discoveries   434   657   1,091                
Extensions and Improved Recovery   2,378   731   3,109         4   3   7    
Economic Factors                      
Technical Revisions   (514 ) (968 ) (1,482 )       16   (18 ) (2 )  
Production   (2,974 )   (2,974 )       (13 )   (13 )  

 
 
December 31, 2009   25,452   7,287   32,739         120   36   156    

 
 
 
UNITED STATES
  Associated and
Non-Associated Gas
(Natural Gas)

  Shale Gas
  Total
   
Factors   Proved   Probable   Proved
Plus
Probable
  Proved   Probable   Proved
Plus
Probable
  Proved   Probable   Proved
Plus
Probable
   

 
 
    (MMcf)   (MMcf)   (MMcf)   (MMcf)   (MMcf)   (MMcf)   (MBOE)   (MBOE)   (MBOE)    
December 31, 2008   40,668   23,483   64,151         33,019   10,832   43,851    
Acquisitions         5,000   2,980   7,980   833   497   1,330    
Divestments                      
Discoveries   591   970   1,561         532   819   1,351    
Extensions and Improved Recovery   2,949   1,289   4,238   3,313   13,773   17,086   3,425   3,245   6,670    
Economic Factors                      
Technical Revisions   10,063   (8,657 ) 1,406   2   10   12   1,181   (2,429 ) (1,248 )  
Production   (4,822 )   (4,822 ) (188 )   (188 ) (3,822 )   (3,822 )  

 
 
December 31, 2009   49,449   17,085   66,534   8,127   16,763   24,890   35,168   12,964   48,132    

 
 

(continues on next page)

38      ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM


 

Reconciliation of Company Interest Reserves (continued)


Total Oil and Gas Reserves

TOTAL
  Light & Medium Oil
  Heavy Oil
  Natural Gas Liquids
   
Factors   Proved   Probable   Proved
Plus
Probable
  Proved   Probable   Proved
Plus
Probable
  Proved   Probable   Proved
Plus
Probable
   

 
 
    (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)    
December 31, 2008   94,553   26,141   120,694   33,139   12,790   45,929   13,052   4,765   17,817    
Acquisitions   413   170   583         5   3   8    
Divestments   (1,090 ) (279 ) (1,369 )       (42 ) (11 ) (53 )  
Discoveries   434   657   1,091                
Extensions and Improved Recovery   3,299   1,000   4,299   947   831   1,778   106   90   196    
Economic Factors   197   (2 ) 195   (18 ) 3   (15 ) (73 ) (19 ) (92 )  
Technical Revisions   (2,649 ) (3,624 ) (6,273 ) 3,737   (1,277 ) 2,460   (765 ) (1,074 ) (1,839 )  
Production   (8,652 )   (8,652 ) (3,374 )   (3,374 ) (1,530 )   (1,530 )  

 
 
December 31, 2009   86,505   24,063   110,568   34,431   12,347   46,778   10,753   3,754   14,507    

 
 
 
TOTAL
  Associated and
Non Associated Gas
(Natural Gas)

  Shale Gas
  Total
   
Factors   Proved   Probable   Proved
Plus
Probable
  Proved   Probable   Proved
Plus
Probable
  Proved   Probable   Proved
Plus
Probable
   

 
 
    (MMcf)   (MMcf)   (MMcf)   (MMcf)   (MMcf)   (MMcf)   (MBOE)   (MBOE)   (MBOE)    
December 31, 2008   1,066,534   421,134   1,487,668         318,500   113,885   432,385    
Acquisitions   275   171   447   5,000   2,980   7,980   1,298   698   1,996    
Divestments   (755 ) (130 ) (885 )       (1,257 ) (312 ) (1,569 )  
Discoveries   949   1,059   2,008         593   832   1,425    
Extensions and Improved Recovery   8,890   9,207   18,097   3,313   13,773   17,086   6,384   5,753   12,137    
Economic Factors   (10,072 ) (4,395 ) (14,467 )       (1,572 ) (751 ) (2,323 )  
Technical Revisions   (200,777 ) (159,900 ) (360,677 ) 2   10   12   (33,141 ) (32,623 ) (65,764 )  
Production   (119,011 )   (119,011 ) (188 )   (188 ) (33,423 )   (33,423 )  

 
 
December 31, 2009   746,034   267,146   1,013,180   8,127   16,763   24,890   257,382   87,482   344,864    

 
 

ENERPLUS RESOURCES 2009 ANNUAL INFORMATION FORM      39


Reconciliation of Gross Reserves


Canadian Oil and Gas Reserves

CANADA
  Light & Medium Oil
  Heavy Oil
  Natural Gas Liquids
   
Factors   Proved   Probable   Proved
Plus
Probable
  Proved   Probable   Proved
Plus
Probable
  Proved   Probable   Proved
Plus
Probable
   

 
 
    (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)   (Mbbls)    
December 31, 2008   67,720   19,045   86,765   33,104   12,765   45,869   12,738   4,648   17,386    
Acquisitions   413   170   583         5   3   8    
Divestments   (1,090 ) (279 ) (1,369 )       (42 ) (11 ) (53 )  
Discoveries                      
Extensions and Improved Recovery   900   265   1,165   947   831   1,778   94   85   179    
Economic Factors   197   (2 ) 195   (18 ) 3   (15 ) (73 ) (19 ) (92 )