notes to consolidated financial statements

(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 GAAP is disclosed in Note 12.   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 the recoverable reserves are charged to earnings.   Proceeds from the sale of petroleum and natural gas properties are applied against 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.

(d) Impairment Test

The Fund has prospectively adopted CICA Accounting Guideline 16 "Oil and gas accounting - full cost" ("AcG-16").   Pursuant to AcG-16, the Fund places a limit 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 un-discounted 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 NI 51-101. The adoption of this guideline had no impact on the financial statements.

(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) Site Restoration and Abandonment

The provision for estimated site restoration costs is determined using the unit-of-production method and is included in depletion, depreciation and amortization expense ("DD&A"). Actual site restoration costs are charged against the accumulated liability.

(g) 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.

(h) 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 are recognized in oil and gas revenues at the time each transaction under a contract is settled. The costs or proceeds realized from holding interest rate swaps are recognized in interest expense at the time each transaction is settled.

(i) 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.

(j) Accounting for Unit Based Compensation

Effective for the fiscal years beginning on or after January 1, 2003, the Fund prospectively adopted CICA Handbook section 3870, " Stock based compensation ", 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 and amounts to be withheld for debt repayment, capital expenditures and acquisitions.   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 is credited to unitholders' capital. Rights granted prior to January 1, 2003 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.

(k) Disclosure of Guarantees

The Fund adopted CICA Accounting Guideline 14 "Disclosure of Guarantees".   Pursuant to the guideline the Fund has disclosed all material guarantees issued to third parties.    

2. Property, Plant and Equipment

($ thousands)	2003	2002
Property, plant and equipment	$3,384,572	$3,071,298
Accumulated depletion and depreciation	(936,207)	(697,153)
Net property, plant and equipment	$2,448,365	$2,374,145

Included in the depletion and depreciation calculation are future capital costs of $180,700,000 (2002 - $203,410,000) and capitalized G&A of $11,847,000 (2002 - $9,091,000).

An impairment test calculation was performed on the Fund's PP&E at December 31, 2003 in which the estimated un-discounted future net cash flows associated with the proved reserves exceeded the carrying amount of the Fund's PP&E.   A similar test performed at January 1, 2003 upon adoption of AcG-16 also resulted in a surplus. Further, no impairment would have been recognized at December 31, 2003 under the prior accounting policy.

The following table outlines benchmark prices used in the impairment test at December 31, 2003:

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

3. Long-Term Debt

($ thousands)	2003	2002
Bank credit facilities (a)	$ -	$93,401
Senior unsecured notes (b)	338,117	268,328
Total long-term debt	$338,117	$361,729

(a)   Bank Credit Facilities

On May 31, 2003, the Fund's borrowing base was increased to $850,000,000. At year-end, Enerplus had bank facilities of $508,880,000 available under two facilities consisting of a demand operating line of credit of $31,672,000 and a $477,208,000, 364 day revolving committed facility with an incremental two-year term. Various borrowing options are available under the facility including prime rate based advances and banker's acceptance loans.

In the event that the revolving bank line is not extended at the end of the 364 day revolving period, no principal payments are required during the first year of the term period. However, Enerplus will be required to maintain certain minimum balances on deposit with the syndicate agent.

Since a demand for payment with respect to the operating facility would be financed by the revolving facility, no portion of the operating facility has been classified as current.

(b) 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 DD&A over the term of the notes.   As at December 31, 2003, the amount remaining to be amortized associated with these costs was $465,000. The notes are subject to fluctuations in foreign exchange rates.   At December 31, 2003 the notes were carried at $69,789,000 with the resulting $3,003,000 gain on translation of foreign debt being included in the determination of net income for the year.

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 DD&A over the term of the notes.   As at December 31, 2003, the amount remaining to be amortized was $1,650,000 (2002 - $1,807,000).   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 unsecured 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 should cash flow be insufficient to repay the Combined Facilities.

4. Fund Capital

(a) Unitholders' Capital

Trust Units

Authorized: Unlimited number of trust units

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).

On November 29, 2002, Enerplus completed an equity offering of 7,959,300 trust units at a price of $26.00 per trust unit for gross proceeds of $206,942,000 ($193,738,000 net of issuance costs).

On September 12, 2002, Enerplus completed an equity offering of 4,750,000 trust units at a price of $26.85 per trust unit for gross proceeds of $127,538,000 ($120,886,000 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 twenty 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.   During 2003, $18,956,000 (2002 - $12,284,000) was raised pursuant to the DRIP.

Trust units are redeemable at any time, on demand by unitholders, at 85% of the current market price.   Redemptions cannot exceed $500,000 during any calendar month.   During 2003, 24,000 units were redeemed at a cost of $590,000 to the Fund.   No units were redeemed during 2002.

(b) Trust Unit Rights Incentive Plan

As at December 31, 2003, a total of 2,192,000 rights pursuant to the Trust Unit Rights Incentive Plan ("Rights Plan") at an average exercise price of $30.05 were outstanding.   This represents 2.3% of the total trust units outstanding of which 430,000 rights with an average exercise price of $24.03 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, 2003, reduced the exercise price of the outstanding rights by $1.47 per trust unit of which a $0.39 reduction is effective January 2004 and a $0.39 reduction is effective April 2004.

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, 2003:

Rights Outstanding at	Original Exercise	Exercise Price after	Expiry Date	Rights Exercisable
December 31, 2003 (000's)	Price	Price Reductions	December 31	December 31, 2003 (000's)
429	$24.50	$23.28	2007	264
10	25.45	24.35	2008	1
26	26.40	25.30	2008	3
35	27.33	26.30	2008	5
585	26.09	25.20	2008	157
135	27.70	27.01	2009	-
144	33.00	32.62	2009	-
110	36.00	36.00	2009	-
718	37.62	37.62	2009	-
2,192	$30.63	$30.05		430

In accordance with the early adoption provision of the CICA Handbook Section 3870, non-cash compensation costs of $1,364,000 ($0.02 per unit) related to the rights issued during 2003 have been charged to general and administrative expense 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.

(c) Trust Unit Option Plan

As at December 31, 2003, 4,000 options pursuant to the Trust Unit Option Plan were outstanding and exercisable. These options are exercisable at an average price of $22.90 and expire December 31, 2004.   During the year ended December 31, 2003, 117,000 options were exercised at a weighted average price of $22.03 and 2,000 options were cancelled at a weighted average price of $22.90. No new options have been granted under the Trust Unit Option Plan since December 31, 2000 as this plan was superseded by the Rights Plan discussed above.

5. 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 taxable income to unitholders.

For 2003, the Fund had taxable income of $307,000,000 (2002 - $157,100,000) or $3.53 per trust unit (2002 - $2.15 per trust unit). Taxable income of the Fund is comprised of dividend, royalty and interest 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, 2003 are $370,681,000 and $29,381,000 respectively (2002 - $355,456,000 and $22,608,000).

(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:

6. Related Party Transactions

On April 23, 2003, the Fund internalized its management contract for total cash consideration of $55,100,000.   The amount was expensed during the second quarter of 2003, and consisted of a cash payment of $48,898,000 to acquire the outstanding common shares of Enerplus Global Energy Management Company ("EGEM") from an indirect subsidiary of El Paso Corporation ("El Paso").   Retention bonuses of $4,700,000 and additional costs of $1,502,000 were also included as part of the internalization expense.

Prior to the internalization transaction the Fund paid management fees to EGEM.   The management fees consisted of a base fee which represented 2.75% of net operating income and a performance fee that was based on the total return and relative performance of the Fund compared to other senior conventional oil and gas trusts.   During 2002, management fees totaled $21,576,000.   In conjunction with the internalization transaction management fees for the period January 1, 2003 to April 23, 2003 were fixed at $3,200,000.   All management fees have been eliminated subsequent to the internalization transaction.

Pursuant to a share purchase agreement dated June 21, 2001, the Fund acquired all of the outstanding common shares of ERC from EGEM.   Consideration for the shares was $2,545,000 which was payable over five years as a reduction in management fees.   This reduction in management fees amounted to $158,000 for the period January 1, 2003 to April 23, 2003.   The remaining payable balance was eliminated as a result of the internalization transaction.

In prior years, Enerplus had entered into financial instrument contracts at market rates with an indirect subsidiary of El Paso.   These contracts expired during the fourth quarter of 2003.

7. Corporate Acquisitions

The fair values of the assets acquired and liabilities assumed for the following acquisitions are summarized as follows:

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

On March 5, 2003, the Fund acquired all of the outstanding 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 subsequent to March 5, 2003 are included in the Fund's consolidated financial statements.

(b )Celsius Energy Resources Ltd.

On October 21, 2002, the Fund acquired all the outstanding common shares and retired the debt of Celsius Energy Resources Ltd. ("Celsius"), for consideration of $161,403,000, which was comprised of $160,950,000 in cash and related costs of $453,000. Available lines of credit financed the acquisition, which has been accounted for using the purchase method of accounting for business combinations. Results from operations subsequent to October 21, 2002 are included in the Fund's consolidated financial statements.

8. Financial Instruments

The Fund's financial instruments represented in the balance sheet consist of cash, accounts receivable, other current assets, current liabilities and long-term debt.

The carrying value of cash, accounts receivable and current liabilities 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 at December 31, 2003 of $16,369,000 exceeded the cost of these securities. 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.   At December 31, 2003 the fair value of these instruments were$72,006,000 and $242,813,000 respectively.    See Note 3 and Note 9.

These estimated 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 single 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) 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, 2003 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

In addition to the cross currency swap described in Note 3, 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 0.85% and 1.05%.   The maturity date of these interest rate swaps were extended by a year to June 2006 during the second quarter of 2003.   The fair value value of the $75,000,000 interest rate swaps as at December 31, 2003 represents an unrealized cost of $1,813,000.  

The fair value of the cross currency swap related to the US$175,000,000 senior unsecured notes as at December 31, 2003 represents an unrealized cost of $25,053,000.

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 outstanding as at December 31, 2003 reflects an unrealized cost of $19,177,000.

The following table summarizes the Fund's crude oil risk management positions:

(1) Financial option transactions entered into during the fourth quarter of 2003.

Natural Gas Instruments

Enerplus has the following physical and financial contracts in place on its natural gas production as described below. The fair value of the financial natural gas contracts as at December 31, 2003 reflects an unrealized cost of $15,549,000.

The following table summarizes the Fund's natural gas risk management positions:

(1) Financial option transactions entered into during the fourth quarter of 2003.

(2) Financial option transaction entered into subsequent to December 31, 2003 that is not included in the fair value.

Electricity Instrument

During the fourth quarter of 2003 , the Fund entered into an electricity swap contract that fixed the price of electricity on 5MW/hr of Alberta Power Pool electricity consumption at $49.75/MWh from January 1, 2004 to December 31, 2004.   The fair value of this instrument as at December 31, 2003 reflects an unrealized gain of $165,000.

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 period.

10. 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 (Josyln Creek Lease).   The acquisition included the assumption of approximately $4,333,000 in contingent project debt that was comprised of $3,360,000 of principal and approximately $973,000 in accrued interest at December 31, 2003.   Interest is accrued at the Bank of Canada prime business rate and is not compounded.   The debt is contingent on both production and pricing 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 $4,379,000.

(d) Guarantee

Subsequent to December 31, 2003, 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, 2003 there were no obligations associated with this guarantee.

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

11. Event Subsequent to December 31, 2003

Subsequent to December 31, 2003, the Fund acquired all of the issued and outstanding shares of Ice Energy Limited for total consideration of approximately $132,200,000.   The acquisition closed January 7, 2004 and will be accounted for using the purchase method of accounting for business combinations. The purchase price allocation has not yet been determined.

12. 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:

(a) Under U.S. GAAP full cost accounting, the carrying value of petroleum and natural gas properties and related facilities, net of deferred income taxes, is limited to the present value of after tax future net revenue from proven reserves, discounted at 10% (based on prices and costs at the balance sheet date), plus the lower of cost and fair value of unproven properties. Under Canadian GAAP, an impairment loss exists when the carrying amount of the Fund's PP&E exceeds the estimated un-discounted 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. The application of the impairment test under U.S. GAAP did not result in a write-down of capitalized costs in either 2003 or 2002.

Where the amount of an impairment test write-down under Canadian GAAP differs from the amount of the write-down under U.S. GAAP, the charge for depletion, depreciation, amortization and accretion will differ in subsequent years.   Historical write-downs for U.S. GAAP have resulted in depletion, depreciation, amortization and accretion being $90,037,000 ($58,623,000 net of tax) lower than for Canadian GAAP for the year ended December 31, 2003. The difference for the year ended December 31, 2002 was an $83,511,000 ($51,443,000 net of tax) reduction in the amount of depletion, depreciation, amortization and accretion recorded.

(b) The Financial Accounting Standards Board's ("FASB") Statement of Financial Standards ("SFAS") 123, "Accounting for Stock-based Compensation" , establishes financial accounting and reporting standards for stock-based employee compensation plans.   As the exercise price of the Trust Unit Rights are subject to downward revisions from time to time, the Rights Plan is a variable compensation plan under U.S. GAAP. Accordingly, compensation expense is determined as the excess of the market price over the exercise price at the end of each reporting period and is deferred and recognized in income over the vesting period of the rights.    In 2003, the Fund voluntarily changed to the fair value method of accounting for unit based compensation under SFAS 123 for all unit right grants and grant modifications after January 1, 2003 using the prospective method described in SFAS 148. This change in accounting policy does not impact the accounting treatment for the Rights Plan as it is a variable compensation plan.

As a result of adoption of fair value accounting under both U.S. GAAP and Canadian GAAP the only remaining difference is that for Canadian GAAP no compensation expense is recorded for rights issued prior to January 1, 2003.   Unit based compensation for the year ended December 31, 2003 on all rights issued was $13,764,000 (2002 - $3,406,000).   The charge to net income for Canadian GAAP was $1,364,000 for the year ended December 31, 2003, resulting in a GAAP difference of $12,400,000.  

(c) Enerplus has prospectively adopted SFAS 123 for the Unit Option Plan using the prospective method described in SFAS 148.   For all options granted prior to January 1, 2003, the Fund applies Accounting Principles Board Opinion No. 25, " Accounting for Stock Issued to Employees", whereby no compensation expense is recognized for options granted with an exercise price equal to the market value of the units on the date of the grant.

No compensation expense has been recorded for Canadian GAAP in relation to the Unit Option Plan and as no options were issued in 2003 under the Unit Option Plan, no compensation expense has been included in income for the Unit Option Plan for U.S. GAAP.   Had compensation cost for Enerplus Unit Options granted prior to January 1, 2003 been determined based on the fair value at the grant dates of the awards consistent with the methodology prescribed by SFAS 123, Enerplus' net income and net income per unit for years ended December 31, 2003 and 2002 would have been the pro forma amounts indicated below:

(d) Effective January 1, 2001, for U.S. GAAP reporting purposes, the Fund adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities" . SFAS 133 establishes accounting and reporting standards requiring that all derivative instruments be recorded in the balance sheet as either an asset or a liability measured at fair value and requires that changes in fair value be recognized currently in income unless specific hedge accounting criteria are met.

With respect to its crude oil and natural gas contracts that do not qualify for hedge accounting treatment under SFAS 133, the Fund has recognized in earnings a gain of $4,733,000 ($3,095,000 net of tax) in 2003 compared to a loss of $25,312,000 ($14,529,000 net of tax) in 2002.

(e) U.S. GAAP requires the reporting of comprehensive income in addition to net earnings.   The Fund's comprehensive income for the year ended December 31, 2003 includes an unrealized loss of $58,556,000 ($38,290,000 net of tax) on instruments qualifying for hedge accounting under SFAS 133. Comprehensive income for the year ended December 31, 2002 includes an unrealized gain of $18,145,000 ($10,415,000 net of tax).   The effect on other comprehensive income of the Fund's financial instruments that qualify for hedge accounting, net of tax, are summarized below:

(f) In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations". SFAS 143 requires liability recognition for retirement obligations associated with tangible long-lived assets.   The obligations included within the scope of SFAS 143 are those for which the Fund faces an obligation for settlement and are to be measured initially at fair value.   The liability is accreted through depletion, depreciation , amortization and accretion expense to account for the passing of time.   The initial fair value of the obligation is to be capitalized as part of the cost of the related long-lived asset and amortized to expense over the useful life of the asset.   SFAS 143 has been adopted, prospectively, as of January 1, 2003.  

The Fund previously estimated costs of abandonment, removal, site reclamation and other similar activities in the total costs that are subject to depreciation, depletion and amortization.   The accumulated amortization of these costs is represented as a liability on the balance sheet, net of actual costs, as accumulated site restoration.   As a result of the application of SFAS 143, Enerplus has recorded an increase to net income of $29,023,000 (net of deferred income taxes of $13,305,000) representing the cumulative effect of adopting SFAS 143. Additionally, the Fund experienced an increase to its asset retirement obligation of $4,279,000, an increase to PP&E of $60,161,000 and an increase in accumulated depreciation, depletion and amortization of $13,554,000.   Furthermore deferred income taxes on the balance sheet have decreased by $13,305,000 as a result of the change in accounting principle.

Depreciation, depletion, amortization and accretion costs for U.S. GAAP include depletion of the capitalized abandonment costs in the amount of $2,797,000 and accretion of the asset retirement obligation in the amount of $4,115,000 for the year ended December 31, 2003.   For Canadian GAAP the amortization of site restoration included in depletion, depreciation and amortization expense for the year ended December 31, 2003 was $7,993,000.   The difference between Canadian and U.S. GAAP results in a $1,081,000 ($704,000 net of tax) reduction in depletion, depreciation, amortization and accretion for U.S. GAAP.

Following is a reconciliation of the asset retirement obligation from January 1, 2003 to December 31, 2003:

(g) The Fund denotes operating activities before changes in operating working capital on the Consolidated Statement of Cash Flows as funds flow from operations. This notation does not have any standardized meaning as prescribed by GAAP, and would not be presented under U.S. GAAP.

(h) Enerplus has adopted FASB Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, for the year ended December 31, 2003.   The fair market value of the Fund's guarantees are considered to be nominal.

DISCLOSURE OF THE IMPACT OF RECENTLY ISSUED ACCOUNTING STANDARDS

In May 2003, the FASB issued Statement of Financial Accounting Standards No. 150 ("FAS 150"), Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity .    In December 2003, the FASB issued Revised FASB Interpretation No. 46, Consolidation of Variable Interest Entities.    These accounting standards are not expected to have a material impact on the Fund at this time.   Enerplus will continue to monitor the relevance of all accounting standards and will measure the impact when they are determined to apply.