(Tabular amounts in thousands of Canadian dollars and thousands of units except per unit amounts)

1. summary of Significant accounting policies

The management of Enerplus Resources Fund ("Enerplus" or the "Fund") prepares the financial statements in accordance with Canadian generally accepted accounting principles ("GAAP"). A reconciliation between Canadian GAAP and United States of America GAAP is disclosed in Note 14.   The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies, if any, as at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The following significant accounting policies are presented to assist the reader in evaluating these consolidated financial statements and, together with the following notes, should be considered an integral part of the consolidated financial statements.

(a) Organization and Basis of Accounting

The Fund is an open-end investment trust created under the laws of the Province of Alberta operating pursuant to the Amended and Restated Trust Indenture between EnerMark Inc., its wholly-owned subsidiary, Enerplus Resources Corporation ("ERC") and CIBC Mellon Trust Company as Trustee.   The beneficiaries of the Fund (the "unitholders") are holders of the trust units issued by the Fund.   As a trust under the Income Tax Act (Canada), Enerplus is limited to holding and administering permitted investments and making distributions to the unitholders.

The Fund's financial statements include the accounts of the Fund and its subsidiaries on a consolidated basis. All inter-entity transactions have been eliminated.

(b) Revenue Recognition

Revenue associated with the sale of crude oil, natural gas and natural gas liquids is recognized when title passes from the Fund to its customers.   A portion of the properties acquired through the acquisition of PCC Energy Inc. and PCC Energy Corp. (collectively, "PCC") are subject to a royalty arrangement with a private company that is structured as a net profits interest.   Results from the operations of PCC, after reduction for this net profits interest, have been included in the Fund's consolidated financial statements subsequent to March 5, 2003.

(c) Property, Plant and Equipment ("PP&E")

The Fund follows the full cost method of accounting for petroleum and natural gas properties under which all acquisition and development costs are capitalized.   Such costs include land acquisition, geological, geophysical and drilling costs for productive and non-productive wells and directly related overhead charges.   Repairs, maintenance and operational costs that do not extend or enhance the recoverable reserves are charged to earnings.   Proceeds from the sale of petroleum and natural gas properties are applied against the capitalized costs.   Gains and losses are not recognized upon disposition of oil and natural gas properties unless such a disposition would alter the rate of depletion by 20% or more.   Net costs related to operating and administrative activities during the development of large capital projects are capitalized until commercial production has commenced.

(d) Impairment Test

A limit is placed on the aggregate carrying value of PP&E (the "impairment test").   An impairment loss exists when the carrying amount of the Fund's PP&E exceeds the estimated undiscounted future net cash flows associated with the Fund's proved reserves.   If an impairment loss is determined to exist, the costs carried on the balance sheet in excess of the discounted future net cash flows associated with the Fund's proved and probable reserves are charged to income. Reserves are determined pursuant to National Instrument 51-101 "Standards of Disclosure for Oil and
Gas Activities".

(e) Depletion and Depreciation

The provision for depletion and depreciation of oil and natural gas assets is calculated using the unit-of-production method based on the Fund's share of estimated proved reserves before royalties. Reserves and production are converted to equivalent units on the basis of 6 Mcf = 1 bbl, reflecting the approximate relative energy content.  

(f) Goodwill

The Fund, when appropriate, recognizes goodwill relating to corporate acquisitions when the total purchase price exceeds the fair value of the net identifiable assets and liabilities of the acquired companies. The goodwill balance is assessed for impairment annually at year-end or as events occur that could result in an impairment.   To assess impairment, the fair value of the Fund is compared to its book value.   If the fair value is less than the book value, a second test is performed to determine the amount of impairment.   The amount of impairment is measured by allocating the fair value to Enerplus' identifiable assets and liabilities as if it had been acquired in a business combination for a purchase price equal to its fair value. If goodwill determined in this manner is less than the carrying value of goodwill, an impairment loss is recognized in the period in which it occurs. Goodwill is stated at cost less impairment and is not amortized.

(g) Asset Retirement Obligations

The Fund recognizes as a liability the estimated fair value of the future retirement obligations associated with property, plant and equipment.   The fair value is capitalized and amortized over the same period as the underlying asset.   The Fund estimates the liability based on the estimated costs to abandon and reclaim its net ownership interest in all wells and facilities and the estimated timing of the costs to be incurred in future periods.   This estimate is evaluated on a periodic basis and any adjustment to the estimate is prospectively applied.   As time passes, the change in net present value of the future retirement obligation is expensed through accretion. Retirement obligations settled during the period reduce the future retirement liability.   No gains or losses on retirement activities were realized, due to settlements approximating the estimates.

(h) Income Taxes

The Fund is a taxable entity under the Income Tax Act (Canada) and is taxable only on income that is not distributed or distributable to the Fund's unitholders. As the Fund distributes all of its taxable income to the unitholders and meets the requirements of the Income Tax Act (Canada) applicable to the Fund, no provision for income tax has been made by the Fund, except for its subsidiaries as noted below.

The Fund follows the liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported in the financial statements of the Fund's corporate subsidiaries and their respective tax bases, using substantively enacted income tax rates. The effect of a change in income tax rates on future income tax liabilities and assets is recognized in income in the period that the change occurs.

(i) Financial Instruments

The Fund is exposed to market risks resulting from fluctuations in commodity prices and interest rates in the normal course of operations.   The Fund uses various types of financial instruments to manage these market risks. Proceeds and costs realized from holding crude oil and natural gas contracts, and interest rate swaps are recognized at the time each transaction under a contract is settled.   The Fund has designated instruments such as swaps, purchased puts and costless collars as qualified hedges and evaluates these instruments quarterly to ensure they effectively hedge the underlying commodity or interest rate.   All other financial contracts do not qualify as hedges.   The gain or loss in fair value of other financial contracts that do not qualify for hedge accounting are taken into income during the period of change and charged to deferred credits or deferred charges on the balance sheet.

(j) Foreign Currency Translation

Monetary assets and liabilities denominated in a foreign currency are translated at the rate of exchange in effect at the balance sheet date.   Revenues and expenses are translated at the monthly average rates of exchange.   Translation gains and losses are included in income in the period in which they arise.

(k) Accounting for Unit Based Compensation

The Fund prospectively adopted CICA Handbook section 3870 "Stock based compensation" on January 1, 2003, which applies to trust unit rights granted on or after that date.   It is not possible to determine a fair value for the unit rights using traditional option pricing models as the exercise price of rights granted under the plan may be reduced in future periods.   The amount of the reduction cannot be reasonably estimated as it is dependent upon a number of factors including, but not limited to, future commodity prices received, future production levels, amounts to be withheld for acquisitions and development activities and the effect of those activities.   As a result, the Fund measures unit compensation expense based on the intrinsic value of the rights and recognizes the amount in income over the vesting period. After the rights have vested, changes in the intrinsic value are recognized to income in the period of change. The intrinsic value is determined to be the excess of the trust unit price over the exercise price of the right at the date of exercise, or the date of the financial statements for unexercised rights.   The change in value is reflected in general and administrative expenses ("G&A") and contributed surplus.   The cash received upon exercise of the rights and the related amount of contributed surplus is credited to unitholders' capital.   Rights granted during 2002 are not included in unit based compensation expense as the Fund discloses the pro forma results based on the intrinsic value of these awards over their vesting period.

2. CHANGES IN ACCOUNTING POLICIES

Hedging Relationships

Effective January 1, 2004, the Fund has adopted the Canadian Institute of Chartered Accountants ("CICA") Accounting Guideline 13, "Hedging Relationships".   The guideline establishes conditions where hedge accounting may be applied.   Where hedge accounting does not apply, changes in the fair values of the financial contracts are taken into income in the period of change and charged to deferred credits or deferred charges on the balance sheet.   This policy has been adopted prospectively pursuant to the adoption provisions of Accounting Guideline 13, and therefore there is no effect on prior periods.

Previously, hedge accounting had been applied to all of the Fund's financial contracts, as they all qualified as hedges for accounting purposes at that time.

As a result of this change, net income was $25,979,000 ($39,160,000 before a future tax recovery of $13,181,000) less than would have otherwise been reported for the year ended December 31, 2004.   This reflects amortization of the deferred financial asset realized upon adoption and unrealized costs on financial contracts that do not qualify for hedge accounting. The future income tax liability has also decreased by $13,181,000 as a result of this accounting change.   Both basic and diluted per trust unit calculations for the year ended December 31, 2004 decreased by $0.26 as a result of adopting this new policy.

Asset Retirement Obligations

Effective January 1, 2004, the Fund retroactively adopted CICA 3110, "Asset Retirement Obligations".   The new standard requires the recognition of the liability associated with the future site reclamation costs of tangible long-lived assets.   The Fund estimates this liability based on the estimated future costs to abandon and reclaim its net ownership interest in all wells and facilities and the estimated timing of the costs to be incurred in future periods.   The liability for future retirement obligations is recorded in the financial statements at the time the liability is incurred.

The Fund had previously provided for future site reclamation and abandonment costs on the unit-of-production method based on the remaining life of the proved reserves and the estimated total future liability.   This estimate was charged to income with the corresponding offset to the accumulated site restoration liability on the balance sheet.

As a result of this change, net income for the year ended December 31, 2004 decreased by $210,000 (2003 - $1,554,000).   This represents the difference between the depletion and accretion recorded and the amortization of future site restoration that would have been recorded under the unit-of-production method.   As a result, basic and diluted per trust unit calculations for the year ended December 31, 2004 were not affected, whereas for the year ended December 31, 2003, both decreased by $0.02.

The December 31, 2003 balance sheet has been restated to reflect the cumulative effects of adopting CICA 3110, as shown in the following table:  

Oil and Gas Transportation

Effective for fiscal years beginning on or after October 1, 2003, the CICA issued Handbook Section 1100, which defines the sources of GAAP that companies must use and effectively eliminates industry practice as a source of GAAP.   In prior years, it had been industry practice for companies to net transportation charges against revenue rather than showing transportation as a separate expense on the income statement.   Effective April 1, 2004, the Fund has recorded revenue before transportation charges and a transportation expense on the income statement.   Prior periods have been reclassified for comparative purposes.   This adjustment has no impact on net income, net income per trust unit, funds flow or funds flow per trust unit for the Fund.

3.   DEFERRED CHARGES AND DEFERRED CREDITS

(1)   Represents the unamortized balance of the senior unsecured notes issue costs.   These costs are being amortized over the life of the notes.

(2)   Represents the fair value of financial contracts on January 1, 2004 for which hedge accounting is no longer applied.   This deferred financial asset is to be amortized over the remaining lives of the associated financial contracts.

(1)   Represents the unamortized balance of deferred   costs on financial contracts as of the date Enerplus Resources Fund was acquired by EnerMark Income Fund.   These deferred costs were being amortized over the remaining life of the financial contracts to which they related, ending October 31, 2004.

(2)   Represents the fair value of financial contracts on January 1, 2004 for which hedge accounting is no longer applied.  

(3)   Changes in the fair value of financial contracts that do not qualify for hedge accounting are taken into income during the period as other financial contracts and reflected as an increase or decrease in the deferred financial liability.  

The following table summarizes the income statement effects of other financial contracts:

In addition during the year ended December 31, 2004 we realized cash costs of $18,167,000, net of gains and losses from financial contracts that qualified as hedges compared to cash costs of $45,808,000 during 2003.

4. ASSET RETIREMENT OBLIGATIONS

Total future asset retirement obligations were estimated by management based on the Fund's net ownership interest in wells and facilities, estimated costs to abandon and reclaim the wells and facilities and the estimated timing of the costs to be incurred in future periods.   The Fund has estimated the net present value of its total asset retirement obligations to be $105,978,000 at December 31, 2004 compared to $63,936,000 at December 31, 2003 based on a total liability of $383,942,000 and $234,102,000 respectively.   These payments are expected to be made over the next 66 years with the majority of costs incurred between 2015 and 2030.   The Fund's credit-adjusted rate of 6.5% and an inflation rate of 2.0% were used to calculate the present value of the asset retirement obligations for both 2004 and 2003.   Settlements during the year approximated our estimates and as a result, no gains or losses
were recognized.

Following is a reconciliation of the asset retirement obligations:

5. PROPERTY, PLANT AND EQUIPMENT

Capitalized development G&A of $8,451,000 (2003 - $11,847,000) is included in PP&E and the depletion and depreciation calculation includes future capital costs of $279,700,000 (2003 - $180,700,000) identified in our reserve report.   Excluded from PP&E for the depletion and depreciation calculation is $28,574,000 (2003 - $nil) related to the Joslyn development project that has not commenced commercial production.  

An impairment test calculation was performed on the Fund's PP&E at December 31, 2004 in which the estimated undiscounted future net cash flows associated with the proved reserves exceeded the carrying amount of the
Fund's PP&E.  

The following table outlines benchmark prices used in the impairment test at December 31, 2004:

(1) Actual prices used in the impairment test were adjusted for commodity price differentials specific to the Fund

  "signed"
Douglas R. Martin
Director

  "signed"
Robert L. Normand
Director

6.   PROPERTY ACQUISITIONS

Assets of ChevronTexaco Corporation ("ChevronTexaco")

On June 30, 2004 the Fund acquired certain oil and natural gas properties from ChevronTexaco. Total consideration was $467,199,000 financed concurrently by subscription receipts issued on June 15, 2004 and available lines of credit.   Results from operations have been included in Enerplus' financial results from June 30, 2004 forward.  

7.   CORPORATE ACQUISITIONS

The allocation to the fair value of the assets acquired and liabilities assumed plus the future income tax cost are summarized as follows:

(a)   Ice Energy Limited ("Ice Energy")

On January 7, 2004 the Fund acquired all of the outstanding common shares of Ice Energy for $130,544,000, which includes negative working capital assumed.   The excess of the consideration paid over the fair value of the identifiable assets and liabilities resulted in the recording of goodwill.   Available lines of credit financed the acquisition, which has been accounted for using the purchase method of accounting for business combinations.   Results from operations of Ice Energy subsequent to January 7, 2004 are included in the Fund's consolidated financial statements.  

(b)   PCC Energy Inc. and PCC Energy Corp. ("PCC")

On March 5, 2003, the Fund acquired all of the outstanding common shares of PCC, for total cash consideration of $165,815,000 including related costs.   Available lines of credit financed the acquisition, which has been accounted for using the purchase method of accounting for business combinations. Results from operations of PCC subsequent to March 5, 2003 are included in the Fund's consolidated financial statements.

8. LONG-TERM DEBT

(a)   Unsecured Bank Credit Facilities

In November 2004 the Fund negotiated an $850,000,000 unsecured covenant based three-year term facility. At year-end, Enerplus had available credit of $598,331,000 under this facility.   It is extendible each year with a bullet payment required at the end of three years if the facility is not renewed.   Various borrowing options are available under the facility including prime rate based advances and banker's acceptance loans.

Prior to November 2004 the Fund had bank facilities of $659,200,000, consisting of a demand operating line of $31,700,000 and a $627,500,000 364-day revolving committed facility with a two-year term.  

•  Senior Unsecured Notes

On October 1, 2003 Enerplus issued US$54,000,000 senior unsecured notes that mature October 1, 2015.   The notes have a coupon rate of 5.46% priced at par with interest paid semi-annually on April 1 and October 1 of each year.   Principal payments are required in five equal installments beginning October 1, 2011 and ending October 1, 2015. Costs incurred in connection with issuing the notes in the amount of $475,000 are classified as deferred charges on the balance sheet and are being amortized to depletion, depreciation, amortization and accretion ("DDA&A") over the term of the notes.   At December 31, 2004, the amount remaining to be amortized associated with these costs was $425,000 (2003 - $465,000). The notes are subject to fluctuations in foreign exchange rates.  

On June 19, 2002 Enerplus issued US$175,000,000 senior unsecured notes that mature June 19, 2014.   The notes have a coupon rate of 6.62% priced at par, with interest paid semi-annually on June 19 and December 19 of each year.   Principal payments are required in five equal installments beginning June 19, 2010 and ending June 19, 2014.   Costs incurred in connection with issuing the notes in the amount of $1,892,000 are classified as deferred charges on the balance sheet and are being amortized to DDA&A over the term of the notes.   At December 31, 2004, the amount remaining to be amortized was $1,492,000 (2003 - $1,650,000).   Concurrent with the issuance of the notes on June 19, 2002, the Fund entered into a cross currency swap with a syndicate of financial institutions.   Under the terms of the swap, the amount of the notes was fixed for purposes of interest and principal repayments at a notional amount of CDN$268,328,000.   Interest payments are made on a floating rate basis, set at the rate for three-month Canadian banker's acceptances, plus 1.18%.

The bank credit facilities and the senior notes (the "Combined Facilities") are the legal obligation of EnerMark Inc. and are guaranteed by its subsidiaries.   Payments with respect to the Combined Facilities have priority over payments to the Fund and over claims of and future distributions to the unitholders.   However, unitholders have no direct liability beyond their equity investment should cash flow be insufficient to repay the Combined Facilities.

9. Foreign Exchange

The US$54,000,000 senior unsecured notes that are exposed to foreign currency fluctuations are translated into Canadian dollars at the exchange rate in effect at the balance sheet date.   Foreign exchange gains and losses are included in the determination of net income for the year.

10. FUND CAPITAL

(a) Unitholders' Capital

Trust Units

Authorized: Unlimited number of trust units

* Distribution Reinvestment and Unit Purchase Plan

On June 15, 2004 Enerplus completed an equity offering of 8,800,000 subscription receipts at a price of $34.30 per subscription receipt for gross proceeds of $301,840,000 ($286,248,000 net of issuance costs).   The subscription receipts were exchanged for trust units on June 30, 2004 upon closing of the ChevronTexaco asset acquisition.   The holders of the subscription receipts received the June 2004 cash distribution of $0.35 per trust unit and this amount has been included in cash distributions to unitholders.

On December 17, 2003, Enerplus completed an equity offering of 4,400,000 trust units at a price of $35.65 per trust unit for gross proceeds of $156,860,000 ($148,717,000 net of issuance costs).

On July 17, 2003, Enerplus completed an equity offering of 4,900,000 trust units at a price of $30.80 per trust unit for gross proceeds of $150,920,000 ($143,074,000 net of issuance costs).

Pursuant to the monthly Distribution Reinvestment and Unit Purchase Plan ("DRIP"), Canadian unitholders are entitled to reinvest cash distributions in additional trust units of the Fund. Trust units are issued at 95% of the weighted average market price on the Toronto Stock Exchange for the 20 trading days preceding a distribution payment date without service charges or brokerage fees. Eligible unitholders are also entitled to make optional cash payments to acquire additional trust units, however the 5% discount does not apply.  

Trust units are redeemable by unitholders at approximately 85% of the current market price.   Redemptions are limited to $500,000 during any rolling two calendar months.   Redemption requests in excess of $500,000 can be paid using investments of the Fund or a non-interest bearing instrument.   During 2004, 7,000 units were redeemed compared to 2003 when 24,000 were redeemed.

  (b) Trust Unit Rights Incentive Plan

As at December 31, 2004, a total of 2,401,000 rights pursuant to the Trust Unit Rights Incentive Plan ("Rights Plan") at an average exercise price of $34.33 were outstanding.   This represents 2.3% of the total trust units outstanding of which 551,000 rights with an average exercise price of $27.84 were exercisable.   Under the Rights Plan, distributions per trust unit to Enerplus unitholders in a calendar quarter which represent a return of more than 2.5% of the net PP&E of Enerplus at the end of such calendar quarter may result in a reduction in the exercise price of the rights. Results for the year ended December 31, 2004, reduced the exercise price of the outstanding rights by $1.44 per trust unit of which a $0.35 reduction is effective January 2005 and a $0.32 reduction is effective April 2005.

Activity for the rights issued pursuant to the Rights Plan is as follows:

(1)   Exercise price reflects grant prices less reduction in strike price discussed above.

The following table summarizes information with respect to outstanding Unit Rights as at December 31, 2004:

Non-cash compensation costs of $4,668,000 ($0.05 per unit) related to the rights issued since January 1, 2003 have been charged to general and administrative expense during 2004 compared to $1,364,000 ($0.02 per unit)
during 2003.  

The following table outlines the estimated compensation cost associated with the rights issued during 2002 and the pro forma effects on net income and net income per unit, had CICA Handbook section 3870 been applied retroactive to 2002.

11. INCOME TAXES

(a) Enerplus Resources Fund

The Fund is an inter-vivos trust for income tax purposes.   As such, the Fund's income that is not allocated to the Fund's unitholders is taxable. The Fund intends to allocate all income to unitholders.

For 2004, the Fund had taxable income of $381,000,000 (2003 - $307,000,000) or $3.77 per trust unit (2003 - $3.53 per trust unit). Taxable income of the Fund is comprised of dividend, royalty, interest and partnership income, less deductions for Canadian oil and gas property expense ("COGPE") and issue costs.

The amounts of COGPE and issue costs remaining in the Fund at December 31, 2004 are $506,985,000 and $32,297,000 respectively (2003 - $393,317,000 and $29,381,000).

(b) Corporate Subsidiaries

The future income tax liability on the balance sheet arises as a result of the following temporary differences:

The provision for income taxes varies from the amounts that would be computed by applying the combined Canadian federal and provincial income tax rates for the following reasons:

12. financial instruments

The Fund's financial instruments presented on the balance sheet consist of cash, accounts receivable, other current assets, a portion of deferred charges, current liabilities and long-term debt.

The carrying value of cash, accounts receivable, current liabilities and outstanding bank credit facility balances approximate their fair value.   Other current assets are comprised of prepaid expenses and marketable securities. The marketable securities are carried on the balance sheet at the lower of cost and fair value. The fair value of the marketable securities at December 31, 2004 exceeded the cost of these securities by $1,668,000. T he Fund carried US$54,000,000 of fixed rate debt. In addition, it carried US$175,000,000 of fixed rate debt that was converted to CDN$268,328,000 floating rate debt through a cross-currency swap with a syndicate of financial institutions.   At December 31, 2004 the fair values of the senior unsecured notes were $67,224,000 and $225,037,000 respectively. See Note 8 .   In addition $3,143,000 (2003 - $nil) has been included in deferred charges related to derivative instruments that no longer qualify for hedge accounting treatment.   These costs will be amortized over the next year.

The estimated fair values have been determined based on available market information and appropriate valuation methods.   The actual amounts realized may differ from these estimates.

(a) Credit Risk

Most of the Fund's accounts receivable relate to oil and natural gas sales and are exposed to typical industry credit risks.   The Fund manages this credit risk by entering into sales contracts with only highly rated entities and reviewing its exposure to individual entities on a regular basis.   The Fund is also exposed to certain losses in the event of non-performance by counterparties to derivative financial instruments.   This credit risk is managed by the Fund by selecting financially sound counterparties.

(b) Interest Rate Risk

The Fund is exposed to movements in interest rates.   Long-term debt is comprised of both variable rate bank facilities and fixed rate senior notes.   The Fund monitors the interest rate forward market and through the use of interest rate swaps along with the fixed-rate notes has fixed the interest rate on approximately 24% of its debt.   See
part (d) below.

(c) Currency Risk

The Fund is exposed to fluctuations in foreign currency as a result of the issuance of senior unsecured notes denominated in U.S. dollars.   Through the use of a financial swap, the exposure on our US$175,000,000 senior unsecured notes has been converted to Canadian dollar debt.   As well, the Fund has indirect exposure to fluctuations in foreign currency as crude oil sales and a portion of natural gas sales are based on U.S. dollar indices.   We have not entered into any foreign currency derivatives with respect to oil and natural gas sales.

(d ) Derivative Financial Instruments

The Fund uses certain derivative financial instruments to manage its commodity price, foreign currency and interest rate exposures.   The fair values of these instruments are based on an approximation of the amounts that would have been paid to or received from counterparties to settle the instruments outstanding as at December 31, 2004 with reference to forward prices and market valuations provided by independent sources.

The fair values of derivative financial instruments are as follows:  

Interest Rate and Cross Currency Swaps

The Fund has entered into interest rate swaps on $75,000,000 of notional debt at rates varying from 3.74% to 4.70% before banking fees that are expected to range between 0.65% and 0.875%.   These interest rate swaps mature between June 2006 and January 2007.   The fair value value of the $75,000,000 interest rate swaps as at December 31, 2004 represents an unrealized cost of $1,412,000.   These swaps have been designated as hedges for
accounting purposes.

The fair value of the cross currency swap related to the US$175,000,000 senior unsecured notes as at December 31, 2004 represents an unrealized cost of $45,378,000.

Crude Oil Instruments

Enerplus has entered into the following financial option contracts to reduce the impact of a downward movement in crude oil prices. The fair value of the financial crude oil contracts that do not qualify for hedge accounting are described in Note 3 .   The fair value of the financial crude oil contracts that qualify for hedge accounting reflects an unrealized cost of $6,406,000 at December 31, 2004.

The following table summarizes the Fund's crude oil risk management positions at February 18, 2005:

*   Financial contracts that qualify as hedges.

(1) Financial contracts entered into during the fourth quarter of 2004.

(2) Financial contracts entered into subsequent to December 31, 2004 that are not included in the fair values.

Enerplus has physical and financial contracts in place on its natural gas production as described below. The fair value of the financial natural gas contracts that do not qualify for hedge accounting at December 31, 2004 is described in Note 3 .   The fair value of the financial natural gas contracts that qualify for hedge accounting reflects an unrealized cost of $14,723,000 at December 31, 2004.

The following table summarizes the Fund's natural gas risk management positions at February 18, 2005:

*   Financial contracts that qualify as hedges.

(1) Financial contracts entered into during the fourth quarter of 2004.

(2) Financial contracts entered into subsequent to December 31, 2004 that are not included in the fair values.

Electricity Instrument

During the fourth quarter of 2004 , the Fund entered into an electricity swap contract that fixed the price of electricity on 5MWh of Alberta Power Pool electricity consumption at $49.99/MWh from January 1, 2005 to December 31, 2006. This has been designated as a hedge and the fair value of this instrument as at December 31, 2004 reflects an unrealized gain of $20,000.

13. commitments and contingencies

(a) Pipeline Transportation

Enerplus has contracted to transport natural gas with various pipelines totaling 15 MMcf per day until 2008 and a further 5 MMcf per day until 2015.  

(b) Oil Sands Lease #24

During 2002, the Fund acquired a 16% working interest in the Oil Sands Lease #24 (Joslyn Creek Lease).   The acquisition included the assumption of contingent project debt that is comprised of principal up to $3,360,000 plus accrued interest to December 31, 2004 up to $1,136,000.   Interest is accrued at the Bank of Canada prime business rate and is not compounded.   The debt is contingent on production hurdles with respect to development on the lease.   As it is too early in the development of this project to determine if these hurdles will be satisfied, the contingent debt has not been accrued in the consolidated financial statements.

(c) Office Lease

Enerplus has an office lease commitment that extends to November 30, 2009.   Annual costs of this lease commitment, which include rent and operating fees, amount to approximately $4,600,000.

(d) Guarantee

During 2004 Enerplus entered into a guarantee for a maximum of $1,000,000 in its capacity as a partner in a limited partnership, which was established for the purpose of marketing natural gas.   At December 31, 2004 there were no obligations associated with this guarantee.

The Fund may provide indemnifications in the normal course of business that are often standard contractual terms to counterparties in certain transactions such as purchase and sale agreements.   The terms of these indemnifications will vary based upon the contract, the nature of which prevents the Fund from making a reasonable estimate of the maximum potential amounts that may be required to be paid.   Management believes the resolution of these matters would not have a material adverse impact on the Fund's liquidity, consolidated financial position or results
of operations.

Enerplus has the following minimum annual commitments including long-term debt:

In addition the Fund is involved in claims and litigation arising in the normal course of business.   The result of these claims are uncertain and there can be no assurance they will be resolved in favour of the Fund, however management believes the resolution of these matters would not have a material adverse impact on the Fund's liquidity, consolidated financial position or results of operations.

14. differences between canadian and united states generally accepted accounting principles

The Fund's consolidated financial statements have been prepared in accordance with Canadian GAAP. These principles, as they pertain to the Fund's consolidated statements differ from United States GAAP ("U.S. GAAP") as follows:

The application of U.S. GAAP would have the following effects on net income as reported:

The application of U.S. GAAP would have the following effects on the balance sheet as reported: