EX-99.1 2 ex991.htm AFS FOR THE YEAR ENDED DECEMBER 31, 2006 ex991.htm
 
Exhibit 99.1
 
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Enerplus Resources Fund is responsible for establishing and maintaining adequate internal control over financial reporting for the Fund. Under the supervision of our Chief Executive Officer and our Chief Financial Officer we have conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, we have concluded that as of December 31, 2006, our internal control over financial reporting is effective.
 
Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even those systems determined to be effective can provide only reasonable assurance with respect to the financial statement preparation and presentation.

Management’s assessment of the effectiveness of the Fund’s internal control over financial reporting as of December 31, 2006, has been audited by Deloitte & Touche LLP, the Fund’s Independent Registered Chartered Accountants, who also audited the Fund’s Consolidated Financial Statements for the year ended December 31, 2006.

REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS
 
To the Board of Directors and Unitholders of Enerplus Resources Fund:
 
We have audited management's assessment, included in the accompanying Management's Report on Internal Control Over Financial Reporting, that Enerplus Resources Fund and subsidiaries (the “Fund”) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Fund's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Fund's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that the Fund maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Fund maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

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We have also audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2006 of the Fund, and our report dated February 21, 2007 expressed an unqualified opinion on those financial statements.

DELOITTE & TOUCHE LLP  
Independent Registered Chartered Accountants
  
Calgary, Canada
  
February 21, 2007        
“signed”
 

MANAGEMENT’S RESPONSIBILITY FOR FINANCIAL STATEMENTS

In management’s opinion, the accompanying consolidated financial statements of Enerplus Resources Fund (the “Fund”) have been prepared within reasonable limits of materiality and in accordance with Canadian generally accepted accounting principles. Since a precise determination of many assets and liabilities is dependent on future events, the preparation of financial statements necessarily involves the use of estimates and approximations. These have been made using careful judgment and with all information available up to February 21, 2007. Management is responsible for all information in the annual report and for the consistency, therewith, of all other financial and operating data presented in this report.

To meet its responsibility for reliable and accurate financial statements, management has established and monitors systems of internal control which are designed to provide reasonable assurance that financial information is relevant, reliable and accurate, and that assets are safeguarded and transactions are executed in accordance with management’s authorization.

The consolidated financial statements have been examined by Deloitte & Touche LLP, Independent Registered Chartered Accountants. Their responsibility is to express a professional opinion on the fair presentation of the consolidated financial statements in accordance with Canadian generally accepted accounting principles. The Independent Registered Chartered Accountants Report outlines the scope of their examination and sets forth their opinion.

The Audit Committee, consisting exclusively of independent directors, has reviewed these statements with management and the Independent Registered Chartered Accountants and has recommended their approval to the Board of Directors. The Board of Directors has approved the consolidated financial statements of the Fund.

“signed” 
“signed”
Gordon J. Kerr 
Robert J. Waters
President and 
Senior Vice President and
Chief Executive Officer  Chief Financial Officer
 
Calgary, Alberta
February 21, 2007



 
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REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS

To the Board of Directors and Unitholders of Enerplus Resources Fund:
 
We have audited the accompanying consolidated balance sheets of Enerplus Resources Fund and subsidiaries (the “Fund”) as of December 31, 2006 and 2005, and the related consolidated statements of income, accumulated deficit and cash flows for the years then ended. These financial statements are the responsibility of the Fund’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
 
With respect to the financial statements for the year ended December 31, 2006, we conducted our audit in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). With respect to the financial statements for the year ended December 31, 2005, we conducted our audit in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Enerplus Resources Fund and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for the years then ended in conformity with Canadian generally accepted accounting principles.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Fund’s internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 21, 2007 expressed an unqualified opinion on management's assessment of the effectiveness of the Fund's internal control over financial reporting and an unqualified opinion on the effectiveness of the Fund's internal control over financial reporting.
 
 
DELOITTE & TOUCHE LLP  
Independent Registered Chartered Accountants
  
Calgary, Canada
  
February 21, 2007        
“signed”
 



Page 3 of 26

CONSOLIDATED BALANCE SHEETS

As at December 31 (CDN$ thousands)
    
2006
    
2005
  
Assets
              
Current assets
              
Cash
 
$
124
  
$
10,093
  
Accounts receivable
    
175,454
    
170,623
  
Deferred financial assets (Note 2)
    
23,612
    
49,874
  
Other current (Note 10)
    
6,715
    
26,751
  
     
205,905
    
257,341
  
Property, plant and equipment (Note 3)
    
3,726,097
    
3,650,327
  
Goodwill (Note 6)
    
221,578
    
221,234
  
Other assets (Notes 7 and 10)
    
50,224
    
1,721
  
   
$
4,203,804
  
$
4,130,623
  
Liabilities
              
Current liabilities
              
Accounts payable
  
$
284,286
  
$
316,875
  
Distributions payable to unitholders
   
51,723
    
49,367
  
Deferred credits (Note 2)
    
-
    
57,368
  
     
336,009
    
423,610
  
Long-term debt (Note 7)
    
679,774
    
659,918
  
Future income taxes (Note 9)
    
331,340
    
442,970
  
Asset retirement obligations (Note 4)
    
123,619
    
110,606
  
     
1,134,733
    
1,213,494
  
Equity
              
Unitholders’ capital (Note 8)
              
Trust Units
              
Authorized:                        Unlimited
              
Issued and Outstanding:        2006 - 123,150,820
              
                                       2005 - 117,539,331
    
3,713,126
    
3,410,614
  
Accumulated deficit
    
(971,085
)
  
(901,527
)
Cumulative translation adjustment (Note 1(j))
   
(8,979
)
  
(15,568
)
     
2,733,062
    
2,493,519
  
   
$
4,203,804
  
$
4,130,623
  


Signed on behalf of the Board of Directors:


“signed” “signed”
   
Douglas R. Martin      
Robert L. Normand
Director Director
 

CONSOLIDATED STATEMENTS OF ACCUMULATED DEFICIT

 
For the year ended December 31 (CDN$ thousands)
   
2006
    
2005
  
               
Accumulated income, beginning of year
  
$
1,408,178
  
$
976,137
  
Net income
    
544,782
    
432,041
  
Accumulated income, end of year
  
$
1,952,960
  
$
1,408,178
  
               
Accumulated cash distributions, beginning of year
  
$
(2,309,705
)
$
(1,811,500
)
Cash distributions
    
(614,340
)
  
(498,205
)
Accumulated cash distributions, end of year
  
$
(2,924,045
)
$
(2,309,705
)
               
Accumulated deficit, end of year
 
$
(971,085
)
$
(901,527
)


 
Page 4 of 26

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CONSOLIDATED STATEMENTS OF INCOME

For the year ended December 31 (CDN$ thousands except per trust unit amounts)
    
2006
    
2005
  
Revenues
              
Oil and gas sales
  
$
1,595,324
  
$
1,550,569
  
Royalties
    
(293,161
)
  
(296,983
)
Derivative instruments (Notes 2 and 10)
              
Financial contracts - qualified hedges
    
-
    
(27,256
)
Other financial contracts
    
(3,226
)
  
(82,664
)
Other income
    
2,465
    
11,064
  
     
1,301,402
    
1,154,730
  
Expenses
              
Operating
    
251,239
    
216,808
  
General and administrative (Note 8(b))
    
59,937
    
40,375
  
Transportation
   
22,611
    
26,915
  
Interest on long-term debt (Note 7)
    
32,168
    
25,791
  
Foreign exchange (gain)/loss
   
(528
)
  
1,677
  
Depletion, depreciation, amortization and accretion
    
481,598
    
386,545
  
     
847,025
    
698,111
  
Income before taxes
    
454,377
    
456,619
  
Capital taxes
    
3,393
    
6,486
  
Current taxes
    
18,236
    
2,764
  
Future income tax (recovery)/expense (Note 9)
    
(112,034
)
  
15,328
  
Net Income
  
$
544,782
  
$
432,041
  
Net income per trust unit
              
Basic
  
$
4.48
  
$
3.96
  
Diluted
  
$
4.47
  
$
3.95
  
Weighted average number of trust units outstanding (thousands)
             
Basic
    
121,588
    
109,083
  
Diluted
    
121,858
    
109,371
  



 
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CONSOLIDATED STATEMENTS OF CASH FLOWS

For the year ended December 31 (CDN$ thousands)
    
2006
    
2005
  
Operating Activities
              
Net income
  
$
544,782
  
$
432,041
  
Non-cash items add/(deduct):
              
Depletion, depreciation, amortization and accretion
    
481,598
    
386,545
  
Non-cash financial contracts (Note 2)
    
(31,106
)
  
(32,679
)
Non-cash foreign exchange
    
(32
)
  
(2,036
)
Unit based compensation (Note 8)
    
6,323
    
3,040
  
Future income tax (Note 9)
    
(112,034
)
  
15,328
  
Asset retirement obligations settled (Note 4)
    
(11,514
)
  
(7,829
)
     
878,017
    
794,410
  
Increase in non-cash operating working capital
    
(14,321
)
  
(19,777
)
Cash flow from operating activities
    
863,696
    
774,633
  
               
Financing Activities
              
Issue of trust units, net of issue costs (Note 8)
    
296,189
    
507,209
  
Cash distributions to unitholders
    
(614,340
)
  
(498,205
)
Increase in bank credit facilities (Note 7)
    
19,888
    
76,963
  
Decrease in non-cash financing working capital
    
2,356
    
12,924
  
Cash flow from financing activities
    
(295,907
)
  
98,891
  
               
Investing Activities
              
Capital expenditures
    
(496,201
)
  
(373,032
)
Property acquisitions (Note 5)
    
(51,313
)
  
(123,896
)
Property dispositions
    
1,599
    
66,511
  
Corporate acquisitions, net of cash acquired (Note 6)
    
-
    
(483,014
)
Purchase of investments
    
(29,172
)
  
-
  
(Increase)/Decrease in non-cash investing working capital
   
(3,535
)
  
51,045
  
Cash flow from investing activities
    
(578,622
)
  
(862,386
)
               
Effect of exchange rate changes on cash
    
864
    
(1,045
)
Change in cash
   
(9,969
)
  
10,093
  
Cash, beginning of year
    
10,093
    
-
  
Cash, end of year
  
$
124
  
$
10,093
  
               
Supplementary Cash Flow Information
             
Cash income taxes paid
  
$
14,060
  
$
2,669
  
Cash interest paid
  
$
34,924
  
$
24,220
  





 
Page 6 of 26

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. (the Fund’s 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. Many of the Fund’s production activities are conducted through joint ventures and the financial statements reflect only the Fund’s proportionate interest in such activities.

(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 based on volumes delivered and contractual delivery points and price. A portion of the properties acquired through the March 5, 2003 acquisition of PCC Energy Inc. and PCC Energy Corp. are subject to a royalty arrangement with a private company that is structured as a net profits interest. The results from operations included in the Fund's consolidated financial statements for these properties are reduced for this net profits interest.

(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 on a country by country cost centre basis. Such costs include land acquisition, geological, geophysical, drilling costs for productive and non-productive wells, facilities 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”). The Fund performs an impairment test on a country by country basis. An impairment loss exists when the carrying amount of the country’s PP&E exceeds the estimated undiscounted future net cash flows associated with the country’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 country’s proved and probable reserves are charged to income.

(e) Depletion and Depreciation

The provision for depletion and depreciation of oil and natural gas assets is calculated on a country by country basis using the unit-of-production method, based on the country’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.


 
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(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 values of the Canadian and U.S. reporting units are compared to their respective book values. 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 of the reporting unit to its identifiable assets and liabilities as if they had been acquired in a business combination for a purchase price equal to their 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. Goodwill is not deductible for income tax purposes.
 
(g) Asset Retirement Obligations

The Fund recognizes as a liability the estimated fair value of the future retirement obligations associated with PP&E. 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 Canadian income that is not distributed or distributable to the Fund’s unitholders. In the Trust structure, payments made between the Canadian operating entities and the Fund, ultimately transfers both income and future income tax liability to the unitholders. The future income tax liability associated with Canadian assets recorded on the balance sheet is recovered over time through these payments. As the Canadian operating entities transfer all of their Canadian taxable income to the Fund, no provision for current Canadian income tax has been made by any Canadian operating entity.

The U.S. operating entity is subject to U.S. income taxes on its taxable income determined under U.S. income tax rules and regulations. Repatriation of funds from U.S. operations will also be subject to applicable withholding taxes as required under U.S. tax law. A provision has been setup to reflect these current U.S. income taxes.

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 temporary 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 these income tax rates on future income tax liabilities and assets is recognized in income during 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. Prior to December 31, 2005, the Fund designated certain commodity contracts and interest rate swaps as qualified hedges. Effective December 31, 2005, the Fund elected to stop designating commodity contracts as qualified hedges. The fair value of the former commodity hedges has been recorded as a financial liability with an offset to deferred financial assets. The deferred financial asset will be amortized over the remaining lives of the associated financial contracts. The fair value of the financial liability will be determined at each period end with any resulting change in fair value being taken into income in that period.

The gain or loss in fair value of all financial contracts that had not previously qualified for hedge accounting are taken into income during the period of change and charged to deferred credits or deferred financial assets on the balance sheet.

Proceeds or costs realized from holding interest rate swaps are recognized at the time each transaction under a contract is settled and is recorded in interest expense. The Fund has designated the interest rate swaps as qualified hedges and these swaps are evaluated quarterly to ensure they effectively hedge the underlying interest rate.


 
Page 8 of 26

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(j) Foreign Currency Translation

The Fund’s U.S. operations are self-sustaining. Assets and liabilities of these operations are translated into Canadian dollars at period end exchange rates, while revenues and expenses are converted using average rates for the period. Gains and losses from the translation into Canadian dollars are deferred and included in the cumulative translation adjustment as part of unitholders’ equity.

Other monetary assets and liabilities, not related to the Fund’s U.S. operations, are translated into Canadian dollars at rates of exchange in effect at the balance sheet date. The other assets and related depreciation, depletion and amortization, other liabilities, revenue and other expenses are translated into Canadian dollars at rates of exchange in effect at the respective transaction dates. The resulting exchange gains or losses are included in earnings.

(k) Unit Based Compensation

The Fund uses the fair value method of accounting for the trust unit rights incentive plan. Under this method, the fair value of the rights is determined on the date in which fair value can reasonably be determined, generally being the grant date. This amount is charged to earnings over the vesting period of the rights, with a corresponding increase in contributed surplus. When rights are exercised, the proceeds, together with the amount recorded in contributed surplus, are recorded to unitholders’ capital.

2. DEFERRED FINANCIAL ASSETS AND DEFERRED CREDITS

The deferred financial assets of $23,612,000 at December 31, 2006 consist of the fair value of the financial instruments of $49,268,000 less the related deferred premiums of $25,656,000.

Deferred Financial Assets ($ thousands)
       
Fair value of financial instruments
        
    Deferred financial assets as at December 31, 2005
  
$
49,874
  
    Deferred financial credits as at December 31, 2005
    
(57,368
)
    Change in fair value - other financial contracts (1)
    
80,980
  
    Amortization of deferred financial assets (2)
    
(49,874
)
   
$
23,612
  
(1) 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 asset or liability.
(2) Represents the amortization of the fair value of financial contracts on December 31, 2005 for which hedge accounting is no longer applied. These deferred financial assets are fully amortized at December 31, 2006.


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

Other Financial Contracts ($ thousands)
    
2006
    
2005
  
Change in fair value
 
$
(80,980
)
$
(35,823
)
Amortization of deferred financial assets
    
49,874
    
3,144
  
Realized cash costs, net
   
34,332
    
115,343
  
Other financial contracts
  
$
3,226
  
$
82,664
  

During the year ended December 31, 2006, the Fund realized cash costs of $nil from commodity financial contracts that qualified as hedges compared to cash costs of $27,256,000 (net gains and losses) during 2005.


3. PROPERTY, PLANT AND EQUIPMENT

($ thousands)
    
2006
    
2005
  
Property, plant and equipment
  
$
5,855,511
  
$
5,306,137
  
Accumulated depletion, depreciation and accretion
    
(2,129,414
)
  
(1,655,810
)
Net property, plant and equipment
  
$
3,726,097
  
$
3,650,327
  

Capitalized development G&A of $14,111,000 (2005 - $11,571,000) is included in PP&E and the depletion and depreciation calculation includes future capital costs of $472,567,000 (2005 - $464,423,000) included in our reserve reports. Excluded from PP&E for the depletion and depreciation calculation is $81,183,000 (2005 - $61,795,000) related to the Joslyn development project that has not commenced commercial production.

An impairment test calculation was performed on a country by country basis on the PP&E values at December 31, 2006 in which the estimated undiscounted future net cash flows associated with the proved reserves exceeded the carrying amount of the Fund’s PP&E.

Page 9 of 26
 
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The following table outlines benchmark prices and the exchange rate used in the impairment tests for both Canadian and U.S. cost centres at December 31, 2006:

Year
   
WTI Crude Oil(1)
US$/bbl
    
Exchange Rate
US$/CDN$
    
Edm Light Crude(1)
CDN$/bbl
    
Natural Gas 30
day spot @
AECO(1)
CDN$/Mcf
  
2007
  
$
65.73
  
$
0.87
  
$
74.10
  
$
7.72
  
2008
    
68.82
    
0.87
    
77.62
    
8.59
  
2009
    
62.42
    
0.87
    
70.25
    
7.74
  
2010
    
58.37
    
0.87
    
65.56
    
7.55
  
2011
    
55.20
    
0.87
    
61.90
    
7.72
  
Thereafter
    
+ 2.0
%
  
0.87
    
+ 2.0
%
  
+ 2.0
%
(1) Actual prices used in the impairment test were adjusted for commodity price differentials specific to the Fund


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 $123,619,000 at December 31, 2006 compared to $110,606,000 at December 31, 2005 based on a total liability of $436,663,000 and $422,045,000 respectively. These payments are expected to be made over the next 66 years with the majority of costs incurred between 2036 and 2045. To calculate the present value of the asset retirement obligations for 2006 the Fund used a weighted credit-adjusted rate of approximately 6.3% and an inflation rate of 2.0%, the same as for 2005. 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:

($ thousands)
    
2006
    
2005
  
Asset retirement obligations, beginning of year
  
$
110,606
  
$
105,978
  
Changes in estimates
    
12,757
    
8,764
  
Acquisition and development activity
    
5,574
    
6,791
  
Dispositions
    
(45
)
  
(9,413
)
Asset retirement obligations settled
    
(11,514
)
  
(7,829
)
Accretion expense
   
6,241
    
6,315
  
Asset retirement obligations, end of year
  
$
123,619
  
$
110,606
  


5. PROPERTY ACQUISITIONS

Assets of Sleeping Giant LLC (“Sleeping Giant”)

On October 4, 2005 the Fund acquired all ownership interests and retired the debt of Sleeping Giant, a private U.S. company holding additional working interests in certain properties of Lyco Energy Corporation for total cash consideration of $111,914,000 which was financed through existing credit facilities. The fair value of this consideration was allocated to cash and positive working capital assumed of $5,754,000 and PP&E of $106,160,000. This acquisition has been accounted for as an asset acquisition. The operating results of Sleeping Giant subsequent to October 4, 2005 are included in the Fund’s consolidated financial statements.

6. 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:

($ thousands)
    
2005
Lyco
   
2005
TriLoch
  
Property, plant and equipment
  
$
506,379
  
$
77,786
  
Goodwill (with no tax base)
    
179,019
    
18,450
  
Future income taxes
    
(179,019
)
  
(18,450
)
     
506,379
    
77,786
  
Cash
    
27,231
    
-
  
Non-cash working capital deficiency
    
(31,664
)
  
(399
)
Net assets acquired
  
$
501,946
  
$
77,387
  
 
 
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Goodwill is comprised of the following:

Goodwill ($ thousands)
    
2006
    
2005
  
Balance, beginning of year
  
$
221,234
  
$
29,082
  
Lyco acquisition
    
-
    
179,019
  
TriLoch acquisition
    
-
    
18,450
  
Foreign exchange (1)
    
344
    
(5,317
)
Balance, end of year
  
$
221,578
  
$
221,234
  
(1) The foreign exchange results from the translation of Lyco goodwill at the period end rate.

Lyco Energy Corporation (“Lyco”)

On August 30, 2005 the Fund acquired all the outstanding common shares and retired the debt including all outstanding mandatorily redeemable preferred shares of Lyco, a private U.S. company operating in the states of Montana and North Dakota. Total consideration was approximately $501,946,000, and the Fund assumed a net working capital deficiency of $4,433,000. Goodwill of $179,019,000 was recorded based on the excess of the consideration paid over the value assigned to the identifiable assets and liabilities including the future income tax liability. The acquisition, which was financed through an equity offering and available credit facilities, has been accounted for using the purchase method of accounting for business combinations. Results from the operations of Lyco subsequent to August 30, 2005 are included in the Fund’s consolidated financial statements.

TriLoch Resources Inc. (“TriLoch”)

On July 1, 2005 the Fund acquired all the outstanding common shares of TriLoch, a public Alberta corporation operating in southern Alberta, in exchange for 1,632,516 trust units of the Fund with a recorded value of $69,088,000. The trust unit value was based on the weighted average price of the Fund’s trust units on the Toronto Stock Exchange during the five day trading period surrounding the announcement of the TriLoch transaction. Total consideration was $77,387,000 consisting of units, deal costs and the retirement of TriLoch’s bank indebtedness. The Fund also assumed a working capital deficiency of $399,000. Goodwill of $18,450,000 has been recorded as a result of the excess of the consideration paid over the value allocated to the identifiable assets and liabilities including the future income tax liability. This acquisition has been accounted for using the purchase method of accounting for business combinations. Results from the operations of TriLoch subsequent to July 1, 2005 are included in the Fund’s consolidated financial statements.

7. LONG-TERM DEBT

($ thousands)
    
2006
    
2005
  
Bank credit facilities (a)
  
$
348,520
  
$
328,632
  
Senior notes (b)
              
US$175 million (issued June 19, 2002)
    
268,328
    
268,328
  
US$54 million (issued October 1, 2003)
   
62,926
    
62,958
  
Total long-term debt
  
$
679,774
  
$
659,918
  

(a) Unsecured Bank Credit Facility

Enerplus has an $850,000,000 unsecured covenant based three year term facility and has the ability to extend the facility each year or repay the entire balance at the end of the three year term. During 2006, the facility was extended until November 2009. At December 31, 2006, Enerplus had available credit of $501,480,000 under this facility. The facility is extendible each year with a bullet payment required at the end of the three year term. Various borrowing options are available under the facility including prime rate based advances and bankers’ acceptance loans. This facility carries floating interest rates that are expected to range between 55.0 and 110.0 basis points over bankers’ acceptance rates, depending on Enerplus’ ratio of senior debt to earnings before interest, taxes and non-cash items. The effective interest rate on the facility for the year ended December 31, 2006 was 4.8% (2005 - 3.4%).


 
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(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 as a part of depletion, depreciation, amortization and accretion (“DDA&A”) over the term of the notes. At December 31, 2006, the amount remaining to be amortized associated with these costs was $346,000 (2005 - $386,000). 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, 2006, the amount remaining to be amortized was $1,177,000 (2005 - $1,335,000). 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 bankers’ acceptances, plus 1.18%.

The bank credit facility 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.


8. FUND CAPITAL

(a) Unitholders’ Capital

Trust Units

Authorized: Unlimited number of trust units

(thousands)
  
2006
2005
Issued:
   
Units
    
Amount
    
Units
    
Amount
  
Balance before Contributed Surplus, beginning of year
    
117,539
    
3,407,567
    
104,124
  
$
2,826,641
  
Issued for cash:
                          
Pursuant to public offerings
    
4,370
    
240,287
    
10,638
    
466,885
  
Pursuant to rights plans
    
640
    
22,974
    
805
    
24,737
  
Trust unit rights incentive plan (non-cash) - exercised
    
-
    
3,065
    
-
    
4,629
  
DRIP*, net of redemptions
    
602
    
32,928
    
339
    
15,613
  
Issued for acquisition of corporate and property interests (non-cash)
    
-
    
-
    
1,633
    
69,062
  
     
123,151
    
3,706,821
    
117,539
    
3,407,567
  
Contributed Surplus (Trust Unit Rights Plan)
   
-
    
6,305
    
-
    
3,047
  
Balance, end of year
   
123,151
  
$
3,713,126
    
117,539
  
$
3,410,614
  
* Distribution Reinvestment and Unit Purchase Plan

Contributed surplus ($ thousands)
    
2006
    
2005
  
Balance, beginning of year
  
$
3,047
  
$
4,636
  
Trust unit rights incentive plan (non-cash) - exercised
    
(3,065
)
  
(4,629
)
Trust unit rights incentive plan (non-cash) - expensed
    
6,323
    
3,040
  
Balance, end of year
  
$
6,305
  
$
3,047
  

On March 20, 2006 the Fund closed an equity offering of 4,370,000 units at a price of $58.00 per unit for gross proceeds of $253,460,000 ($240,287,000 net of issuance costs).

On August 9, 2005 the Fund completed a Canadian equity offering of 10,637,500 subscription receipts at a price of $46.25 per subscription receipt for gross proceeds of $491,984,000 ($466,885,000 net of issuance costs). The subscription receipts were exchanged for an equal number of trust units on August 30, 2005 upon the closing of the Lyco transaction.

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On July 1, 2005 the Fund issued 1,632,516 trust units pursuant to the acquisition of TriLoch valued at $42.32 per trust unit, being the weighted average trading price of the Fund’s trust units on the Toronto Stock Exchange during the five day trading period surrounding the announcement of the TriLoch transaction, for a recorded value of $69,088,000 ($69,062,000 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.

(b) Trust Unit Rights Incentive Plan

As at December 31, 2006 a total of 3,079,000 rights issued pursuant to the Trust Unit Rights Incentive Plan (“Rights Plan”) were outstanding at an average exercise price of $48.53. This represents 2.5% of the total trust units outstanding of which 809,000 rights, with an average exercise price of $39.81, 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, 2006 reduced the exercise price of the outstanding rights by $2.02 per trust unit of which a $0.51 reduction is effective January 2007 and a $0.50 reduction is effective April 2007. Plan members have the choice to exercise rights using the original exercise price or a reduced strike price. In certain circumstances, it may be more advantageous to use the original exercise price as it could effectively lower the plan member’s tax rate on the transaction.

The Fund uses a binomial lattice option-pricing model to calculate the estimated fair value of rights granted under the plan. The following assumptions were used to arrive at the estimate of fair value:

     
2006
    
2005
  
Dividend yield
    
9.26
%
  
8.97
%
Right’s exercise price reduction
  
$
1.61
  
$
1.43
  
Volatility
    
25.61
%
  
21.46
%
Risk-free interest rate
    
4.13
%
  
3.70
%
Forfeiture rate
    
2.80
%
  
4.60
%

The fair value of the rights granted under the plan during 2006 ranged between 12% and 14% (2005 - 9% and 10%) of the underlying market price of a trust unit on the grant date.

During the year the Fund expensed $6,323,000 or $0.05 per unit (2005 - $3,040,000 or $0.03 per unit) of unit based compensation expense using the fair value method. The remaining future fair value of the rights of $10,113,000 at December 31, 2006 (2005 - $6,380,000) will be recognized in earnings over the remaining vesting period of the rights. Activity for the rights issued pursuant to the Rights Plan is as follows:

   
2006
2005
   
Number of Rights (000’s) 
    
Weighted Average Exercise Price(1)
 
  
Number of Rights (000’s
)
  
Weighted Average Exercise Price(1)
 
Trust unit rights outstanding
                          
Beginning of year
    
2,621
  
$
42.80
    
2,401
  
$
34.33
  
Granted
    
1,473
    
54.49
    
1,125
    
53.07
  
Exercised
    
(640
)
  
35.94
    
(805
)
  
30.72
  
Cancelled
    
(375
)
  
46.35
    
(100
)
  
37.15
  
End of year
    
3,079
    
48.53
    
2,621
    
42.80
  
Rights exercisable at the end of the year
    
809
  
$
39.81
    
643
  
$
32.46
  
(1) Exercise price reflects grant prices less reduction in strike price discussed above.
 
The following table summarizes information with respect to outstanding rights as at December 31, 2006. Rights vest between one and three years and expire between four and six years.

 
Page 13 of 26
 
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Rights Outstanding at December 31, 2006 (000’s)
    
Original Exercise Price
    
Exercise Price after Price Reductions
    
Expiry Date December 31
    
Rights Exercisable at December 31, 2006 (000’s
)
10
  
$
24.50
  
$
18.41
    
2007
    
10
  
1
    
26.40
    
20.43
    
2008
    
1
  
38
    
26.09
    
20.33
    
2008
    
38
  
6
    
27.70
    
22.14
    
2009
    
6
  
23
    
33.00
    
27.75
    
2009
    
23
  
19
    
36.00
    
31.13
    
2009
    
19
  
192
    
37.62
    
33.14
    
2009
    
192
  
14
    
40.70
    
36.61
    
2010
    
1
  
30
    
37.25
    
33.53
    
2010
    
8
  
58
    
38.83
    
35.51
    
2010
    
40
  
387
    
40.80
    
37.83
    
2010
    
208
  
80
    
45.55
    
42.90
    
2011
    
9
  
92
    
44.86
    
42.56
    
2011
    
16
  
143
    
49.75
    
47.85
    
2011
    
46
  
566
    
56.93
    
55.44
    
2011
    
192
  
178
    
56.55
    
55.54
    
2012
    
-
  
436
    
54.21
    
53.70
    
2012
    
-
  
320
    
56.00
    
56.00
    
2012
    
-
  
486
    
52.90
    
52.90
    
2012
    
-
  
3,079
  
$
50.10
  
$
48.53
          
809
  


(c) Basic and Diluted per Trust Unit Calculations

Net income per trust unit has been determined based on the following:

(thousands)
    
2006
    
2005
  
Weighted average units
    
121,588
    
109,083
  
Dilutive impact of rights
   
270
    
288
  
Diluted trust units
    
121,858
    
109,371
  

No rights were excluded in calculating the weighted average number of diluted units for the year ended December 31, 2006. In 2005 we excluded 132,511 rights because their exercise price was greater than the annual average unit market price of $48.08. During the last two years, outstanding rights were the only potential dilutive instrument.

9. 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 2006, the Fund had taxable income of $588,000,000 (2005 - $451,000,000) or $4.81 per trust unit (2005 - $4.05 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 trust unit issue costs.

The amounts of COGPE and issue costs remaining in the Fund at December 31, 2006 are $466,700,000 and $35,543,000 respectively (2005 - $466,700,000 and $40,109,000).

Proposed Tax on Income Trusts

On October 31, 2006, the Federal Government announced a new tax on publicly traded flow through entities including Enerplus. The tax would be applicable beginning in 2011 at the rate of 31.5% provided that Enerplus does not exceed the guidance provided on normal growth. Enerplus can issue up to $7.5 billion of new equity before 2011 without exceeding the guidance on normal growth. In addition, we understand that a trust will be able to issue equity to retire debt existing on October 31, 2006 without eroding their safe harbour equity limits.

At the present time, the proposed changes to tax legislation are not substantively enacted. Further, the timing of the enactment or the exact content of the proposed changes is difficult to predict. Therefore, no amounts in respect of this matter are reflected in the future tax liability presented on the balance sheet.

Page 14 of 26
 
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If substantively enacted, the Fund would be treated as a taxable entity resulting in the recording of future income tax assets and liabilities. Enerplus’ future tax liability would be adjusted to include differences between the accounting and tax bases of the trust’s assets and liabilities at the substantively enacted tax rates.

(b) Corporate Subsidiaries

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

($ thousands)
    
Canadian
    
Foreign
    
2006
Total
  
Excess of net book value of property, plant and equipment over the underlying tax bases
  
$
179,770
  
$
183,081
  
$
362,851
  
Asset retirement obligations
    
(37,667
)
  
-
    
(37,667
)
Deferred hedging and other
   
6,963
    
(807
)
  
6,156
  
Future income tax liability
  
$
149,066
  
$
182,274
  
$
331,340
  


($ thousands)
    
Canadian
    
Foreign
    
2005
Total
  
Excess of net book value of property, plant and equipment over the underlying tax bases
  
$
302,610
  
$
183,355
  
$
485,965
  
Asset retirement obligations
    
(37,976
)
  
-
    
(37,976
)
Deferred hedging and other
   
(1,925
)
  
(3,094
)
  
(5,019
)
Future income tax liability
  
$
262,709
  
$
180,261
  
$
442,970
  


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:

($ thousands)
    
2006
    
2005
  
Income before taxes
 
$
454,377
  
$
456,619
  
Computed income tax expense at the enacted rate of 34.88% (38.01% for 2005)
  
$
158,487
  
$
173,564
  
Increase (decrease) resulting from:
              
Net income attributed to the Fund
    
(197,694
)
  
(172,463
)
Non-deductible crown royalties
    
11,878
    
30,652
  
Resource allowance
   
(11,998
)
  
(37,047
)
Amended returns and pool balances
    
(21,446
)
  
16,544
  
Change in tax rate
    
(35,500
)
  
-
  
Other
   
2,475
    
6,842
  
   
$
(93,798
)
$
18,092
  
               
Future income tax (recovery)/expense
  
$
(112,034
)
$
15,328
  
Current tax
  
$
18,236
  
$
2,764
  


The breakdown of our current and future income tax balances between our Canadian and Foreign operations is as follows:

For the year ended December 31, 2006 ($ thousands)
    
Canadian
    
Foreign
    
Total
  
Future income (recovery)/expense
  
$
(113,643
)
$
1,609
  
$
(112,034
)
Current income tax
    
-
    
18,236
    
18,236
  


For the year ended December 31, 2005 ($ thousands)
    
Canadian
    
Foreign
    
Total
  
Future income expense
  
$
8,708
  
$
6,620
  
$
15,328
  
Current income tax
    
-
    
2,764
    
2,764
  

10. FINANCIAL INSTRUMENTS

The Fund’s financial instruments presented on the balance sheet consist of cash, accounts receivable, deferred financial assets, other current assets, other assets, accounts payable, distributions payable to unitholders, deferred credits and long-term debt.

The carrying value of cash, accounts receivable, deferred financial assets, other assets, current liabilities and the outstanding bank credit facility balances approximate their fair value. Other current assets are comprised of prepaid expenses and marketable securities and other assets are comprised of long-term investments. Marketable securities
 
Page 15 of 26
 
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and long-term investments are carried on the balance sheet at the lower of cost and fair value. The fair value of the marketable securities at December 31, 2006 exceeded the cost of these securities by $14,493,000. The book value of other assets at December 31, 2006 of $48,700,000 was lower than the fair value of these assets by $3,231,000.

The 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, 2006 the fair value of the senior unsecured notes was $62,990,000 (for the US$54,000,000 notes) and $208,217,000 (for the US$175,000,000 notes), see Note 7.

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 credit-worthy counterparties 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.

In 2006, approximately 15% of the Fund’s oil and gas sales were made to a AA+ rated counterparty.

(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 20% of its debt. See part (d) below.

(c) Currency Risk

The Fund is exposed to fluctuations in foreign currency as a result of its U.S. operations and 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, 2006 with reference to forward prices and market valuations provided by third party sources.

The fair values of derivative financial instruments are as follows:


 
Page 16 of 26

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Interest Rate Swaps

The Fund has entered into interest rate swaps on $75,000,000 of notional debt at rates varying from 4.10% to 4.61% before banking fees that are expected to range between 0.55% and 1.10%. These interest rate swaps mature between January 2007 and January 2012. The fair value of the $75,000,000 interest rate swaps as at December 31, 2006 represents an unrealized cost of $673,000. These swaps have been designated as a cash flow hedge for accounting purposes.

Cross Currency Interest Rate Swap

The fair value of the cross currency interest rate swap related to the US$175,000,000 senior unsecured notes as at December 31, 2006 represents an unrealized cost of $65,002,000 whereas the fair value of the underlying debt instrument as at December 31, 2006 represents an unrealized gain of $60,111,000. The cross currency swap has been designated as a fair value hedge for accounting purposes.

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 net premium cost of the crude oil instruments entered into as of December 31, 2006 is $20,108,000.

The following table summarizes the Fund’s crude oil risk management positions at February 13, 2007:

           
WTI US$/bbl  
  
   
Daily
Volumes
bbls/day
    
Purchased Put
    
Fixed Price and Swaps
  
Term
                    
January 1, 2007 - December 31, 2007
                    
    Put
   
5,000
  
$
71.00
    
-
  
    Put
   
2,500
  
$
68.00
    
-
  
    Put (1)
    
2,500
  
$
65.70
    
-
  
    Swap (1)
    
2,500
    
-
  
$
66.24
  
(1) Financial contracts entered into during the fourth quarter of 2006.

Natural Gas Instruments

Enerplus has physical and financial contracts in place on its natural gas production as described below. The net premium cost of the natural gas instruments entered into as of December 31, 2006 is $5,548,000.

The following table summarizes the Fund’s natural gas risk management positions at February 13, 2007:


       
AECO CDN$/Mcf 
   
Daily Volumes MMcf/day
    
Sold Call
    
Purchased
Put
    
Sold
Put
    
Fixed Price and Swaps
  
Term
                                
January 1, 2007 - March 31, 2007
                                
    Collar  
    
6.6
  
$
11.45
  
$
9.00
    
-
    
-
  
    Collar (1)
    
9.5
  
$
9.50
  
$
7.00
    
-
    
-
  
    Collar (1)
   
9.5
  
$
10.66
  
$
7.00
    
-
    
-
  
    Costless Collar  
    
6.6
  
$
11.45
  
$
7.70
    
-
    
-
  
    Put (1)
   
6.6
    
-
  
$
7.50
    
-
    
-
  
    Put (1)
    
4.7
    
-
  
$
7.39
    
-
    
-
  
January 1, 2007 - June 30, 2007
                                
    Put (1)
    
4.7
    
-
  
$
7.50
    
-
    
-
  
April 1, 2007 - October 31, 2007
                                
    Collar  
    
6.6
  
$
10.02
  
$
7.50
    
-
    
-
  
    Collar
   
6.6
  
$
9.00
  
$
7.50
    
-
    
-
  
    Collar (1)
   
9.5
  
$
9.10
  
$
7.10
    
-
    
-
  
    Collar (1)
   
9.5
  
$
9.15
  
$
7.14
    
-
    
-
  
    Collar (1)
   
9.5
  
$
9.50
  
$
7.20
    
-
    
-
  
 
 
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    Costless Collar (2)
    
4.7
  
$
8.02
  
$
7.17
    
-
    
-
  
    Costless Collar (2)
    
4.7
  
$
8.23
  
$
7.28
    
-
    
-
  
    Costless Collar (2)
    
4.7
  
$
8.20
  
$
7.50
              
    3-Way option (1)
    
4.7
  
$
9.50
  
$
7.75
  
$
5.49
    
-
  
    Put (1)
    
4.7
    
-
  
$
7.28
    
-
    
-
  
    Swap (1)
    
6.6
    
-
    
-
    
-
  
$
7.60
  
    Swap (1)
    
4.7
    
-
    
-
    
-
  
$
7.33
  
    Swap (1)
    
2.4
    
-
    
-
    
-
  
$
7.84
  
    Swap (1)
    
2.4
    
-
    
-
    
-
  
$
7.96
  
    Swap (2)
    
7.1
    
-
    
-
    
-
  
$
7.17
  
    Swap (2)
    
2.4
    
-
    
-
    
-
  
$
7.70
  
    Swap (2)
    
2.4
    
-
    
-
    
-
  
$
7.53
  
    Swap (2)
    
2.4
    
-
    
-
    
-
  
$
8.35
  
November 1, 2007 - March 31, 2008
                                
    Collar (1)
    
2.4
  
$
9.95
  
$
8.00
    
-
    
-
  
    3-Way option (1)
    
4.7
  
$
10.50
  
$
8.20
  
$
5.70
    
-
  
    Swap (1)
    
4.7
    
-
    
-
    
-
  
$
8.70
  
2007 - 2010
                                
    Physical (escalated pricing)
    
2.0
    
-
    
-
    
-
  
$
2.52
  
(1) Financial contracts entered into during the fourth quarter of 2006.
(2) Financial contracts entered into during the first quarter of 2007.


Electricity Instrument

The Fund has entered into electricity swap contracts that fix the price of electricity. These contracts have been designated as cash flow hedges and the fair value of these instruments as at December 31, 2006 represents an unrealized gain of $1,494,000. Proceeds or costs realized from the electricity contracts are recognized as operating costs.
 
The following table summarizes the Fund’s electricity management positions at February 13, 2007:


Term
    
Volumes MWh
    
Price
CDN$/MWh
  
January 1, 2007 - December 31, 2007
   
5.0
  
$
61.50
  
January 1, 2007 - December 31, 2007
   
4.0
  
$
62.90
  
January 1, 2008 - September 30, 2008
   
4.0
  
$
63.00
  

The Fund did not enter into any new electricity contracts in the fourth quarter of 2006.


11. COMMITMENTS AND CONTINGENCIES

(a) Pipeline Transportation

Enerplus has contracted to transport natural gas with various pipelines totaling 35.3 MMcf/day until 2008; of this amount 5 MMcf/day extends until 2015. Enerplus also has a contract to transport a minimum of 2,480 bbls/day of crude oil from the field to suitable marketing sales points until 2010.

(b) Oil Sands Lease #24

The Fund's acquisition of a working interest in the Joslyn project included the assumption of a proportionate share of certain contingent project debt. Effectively, this debt is comprised of principal of $3,150,000 plus accrued interest to December 31, 2006 of $1,379,000. Interest is accrued at the Bank of Canada prime business rate and is not compounded. The debt is contingent on attaining certain production hurdles with respect to development of the project. As it is still too early to determine if these hurdles will be satisfied, no portion of the contingent debt has been accrued for in the consolidated financial statements.


 
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(c) Office Lease

Enerplus has office lease commitments for both its Canadian and U.S. operations that expire between November 2009 and January 2011. Annual costs of these lease commitments, which include rent and operating fees, amount to approximately $6,700,000.

(d) Guarantees

(i) Corporate indemnities have been provided by the Fund to all directors and certain officers of its subsidiaries and affiliates for various items including, but not limited to, all costs to settle suits or actions due to their association with the Fund and its subsidiaries and/or affiliates, subject to certain restrictions. The Fund has purchased directors’ and officers’ liability insurance to mitigate the cost of any potential future suits or actions. Each indemnity, subject to certain exceptions, applies for so long as the indemnified person is a director or officer of one of the Fund’s subsidiaries and/or affiliates. The maximum amount of any potential future payment cannot be reasonably estimated.

(ii) 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:
 
         
 Minimum Annual Commitment Each Year
    
Total
Committed
after 2011
  
($ thousands)
   
Total
    
2007 
    
2008
    
2009 
     2010     
2011
        
Bank credit facility
  
$
348,520
  
$
-
  
$
-
  
$
348,520
  
$
-
  
$
-
  
$
-
  
Senior unsecured notes
   
331,254
    
-
    
-
    
-
    
53,666
    
66,251
    
211,337
  
Pipeline commitments
    
28,543
    
6,364
    
5,788
    
2,952
    
2,444
    
2,275
    
8,720
  
Office lease
    
20,917
    
6,745
    
6,828
    
6,702
    
592
    
50
    
-
  
Total commitments
  
$
729,234
  
$
13,109
  
$
12,616
  
$
358,174
  
$
56,702
  
$
68,576
  
$
220,057
  

In addition, the Fund is involved in claims and litigation arising in the normal course of business. The resolution of these claims is 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.

12. GEOGRAPHICAL INFORMATION

As at December 31, 2006
($ thousands)
    
Canada
   
U.S.
    
Total
  
Oil and gas revenue
  
$
1,323,631
  
$
271,693
  
$
1,595,324
  
Capital assets
    
3,101,277
    
624,820
    
3,726,097
  
Goodwill
    
47,532
    
174,046
    
221,578
  
                     

As at December 31, 2005
($ thousands)
    
Canada
   
U.S.
    
Total
  
Oil and gas revenue
  
$
1,471,473
  
$
79,096
  
$
1,550,569
  
Capital assets
    
3,054,078
    
596,249
    
3,650,327
  
Goodwill
    
47,532
    
173,702
    
221,234
  


13. EVENTS SUBSEQUENT TO DECEMBER 31, 2006

On January 31, 2007, Enerplus closed the acquisition of gross overriding royalty (“GORR”) interests in the Jonah natural gas field in Wyoming for total consideration of US$52,000,000 (CDN$60,000,000). The full amount of the purchase price will be recorded to PP&E in 2007. This represents a GORR of approximately 0.5% on about 650 producing natural gas wells in the Jonah field.

Page 19 of 26

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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:

($ thousands)
    
2006
    
2005
 
Net income as reported in the Consolidated
             
Statement of Income - Canadian GAAP
  
$
544,782
  
$
432,041
  
Adjustments
              
Depletion, depreciation, amortization and accretion (Note (a))
    
74,391
    
57,050
  
Amortization of financial derivative deferred charges (Note (b))
    
-
    
3,143
  
Unrealized gain (loss) on cross-currency and interest rate swap (Note (b))
    
1,245
    
(4,049
)
Capitalized interest (Note (c))
    
3,436
    
-
  
Compensation expense (Note (d))
    
(2,237
)
  
(19,732
)
Income tax expense of above adjustments, including expense due to change in tax rates of $35,016 for 2006 (2005 - recovery of $2,548)
    
(58,234
)
  
(16,540
)
Net income before cumulative effect of change in accounting principle - U.S. GAAP
    
563,383
    
451,913
  
Cumulative effect of adoption of SFAS 123R (Note (d))
   
-
    
1,753
  
Net income - U.S. GAAP
    
563,383
    
453,666
  
Change in fair value of cash flow hedges, net of tax of $14,595 (2005 - $26,540 net of tax of $9,064) (Note (b))
   
35,287
    
(17,476
)
Change in fair value of available for sale securities, net of tax of $1,998 (2005 - $9,229 net of tax of $3,139) (Note (e))
    
4,829
    
6,090
  
Change in cumulative translation adjustment (Note (g))
    
6,589
    
(15,568
)
Comprehensive income
  
$
610,088
  
$
426,712
  
 
Net income per trust unit before cumulative change in accounting principle
             
Basic
  
$
4.63
  
$
4.14
  
Diluted
  
$
4.62
  
$
4.13
  
Cumulative effect of change in accounting principle
             
Basic
  
$
-
  
$
0.02
  
Diluted
  
$
-
  
$
0.02
  
Net income per trust
             
Basic
  
$
4.63
  
$
4.16
  
Diluted
  
$
4.62
  
$
4.15
  
Weighted average number of trust units outstanding
              
Basic
    
121,588
    
109,083
  
Diluted
    
121,860
    
109,371
  
               
Deficit:
              
Balance, beginning of year - U.S. GAAP
  
$
(3,551,509
)
$
(2,366,709
)
Net income - U.S. GAAP
    
563,383
    
453,666
  
Change in redemption value (Note (f))
    
586,876
    
(1,140,261
)
Cash distributions
    
(614,340
)
  
(498,205
)
Balance, end of year - U.S. GAAP
  
$
(3,015,590
)
$
(3,551,509
)
               
Accumulated other comprehensive income (loss):
              
Balance, beginning of year - U.S. GAAP
  
$
(40,772
)
$
(13,818
)
Change in fair value of cash flow hedges and available for sale securities, net of tax
    
40,116
    
(11,386
)
   Change in cumulative translation adjustment
    
6,589
    
(15,568
)
Balance, end of year - U.S. GAAP
  
$
5,933
  
$
(40,772
)


 
Page 20 of 26

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Reconciliation of Accumulated Other Comprehensive Income (loss):

As at December 31 ($ thousands)
    
2006
    
2005
  
Fair Value of Derivatives Designated as Cash Flow Hedges:
              
    Interest rate swaps
 
$
(673
)
$
(206
)
    Natural gas instruments
   
-
    
(36,553
)
    Crude oil instruments
   
-
    
(13,321
)
    Electricity swaps
   
1,494
    
1,019
  
   
$
821
  
$
(49,061
)
Other items:
              
    Unrealized gain on available for sale securities
    
17,724
    
10,898
  
    Cumulative translation adjustment
    
(8,979
)
  
(15,568
)
    Deferred income taxes
    
(3,633
)
  
12,959
  
Accumulated other comprehensive income (loss)
  
$
5,933
  
$
(40,772
)


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

($ thousands)
    
Canadian
GAAP
    
Increase (Decrease
)
  
U.S.
GAAP
  
December 31, 2006
                    
Assets:
                    
Other current assets (Note (e))
  
$
6,715
  
$
14,493
  
$
21,208
  
Property, plant and equipment, net (Note (a)(c))
    
3,726,097
    
(634,553
)
  
3,091,544
  
Other Assets (Note (e))
    
50,224
    
3,231
    
53,455
  
                     
Liabilities:
                    
Deferred credits/Financial derivative liabilities (Note (b))
  
$
-
  
$
64,181
  
$
64,181
  
Trust unit rights liability (Note (d))
    
-
    
14,298
    
14,298
  
Long-term debt (Note (b))
    
679,774
    
(60,111
)
  
619,663
  
Future income taxes/Deferred income taxes
    
331,340
    
(197,576
)
  
133,764
  
Unitholders’ mezzanine equity (Note (f))
    
-
    
5,305,098
    
5,305,098
  
                     
Unitholder’s Equity:
                    
Unitholders’ capital (Note (f))
  
$
3,706,821
  
$
(3,706,821
)
$
-
  
Contributed surplus (Note (d))
    
6,305
    
(6,305
)
  
-
  
Deficit (Note (f))
    
(971,085
)
  
(2,044,505
)
  
(3,015,590
)
Accumulated other comprehensive income (loss) (Note (b)(e)(g))
    
-
    
5,933
    
5,933
  
Cumulative translation adjustment (Note (g))
    
(8,979
)
  
8,979
    
-
  
December 31, 2005
                   
Assets:
                    
Total current assets (Note (b)(e))
  
$
257,341
  
$
(38,977
)
$
218,364
  
Property, plant and equipment, net (Note (a))
    
3,650,327
    
(712,380
)
  
2,937,947
  
                     
Liabilities:
                    
Deferred credits/Financial derivative liabilities (Note (b))
  
$
57,368
  
$
61,626
  
$
118,994
  
Trust unit rights liability (Note (d))
    
-
    
20,654
    
20,654
  
Long-term debt (Note (b))
    
659,918
    
(56,303
)
  
603,615
  
Future income taxes/Deferred income taxes
    
442,970
    
(272,403
)
  
170,567
  
Unitholders’ mezzanine equity (Note (f))
    
-
    
5,580,869
    
5,580,869
  
                     
Unitholder’s Equity:
                    
Unitholders’ capital (Note (f))
  
$
3,407,567
  
$
(3,407,567
)
$
-
  
Contributed surplus (Note (d))
    
3,047
    
(3,047
)
  
-
  
Deficit (Note (f))
    
(901,527
)
  
(2,649,982
)
  
(3,551,509
)
Accumulated other comprehensive income (loss) (Note (b)(e)(g))
    
-
    
(40,772
)
  
(40,772
)
Cumulative translation adjustment (Note (g))
    
(15,568
)
  
15,568
    
-
  


 
Page 21 of 26

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(a) Property, Plant and Equipment and Depletion, Depreciation, Amortization and Accretion

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 proved reserves, discounted at 10% (based on prices and costs at the balance sheet date), plus the lower of cost and fair value of unproved properties. Under Canadian GAAP, 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. The application of the impairment tests under Canadian and U.S. GAAP did not result in a write-down of capitalized costs in either 2006 or 2005.
 
Where the amount of a ceiling test write-down under Canadian GAAP differs from the amount of the write-down under U.S. GAAP, the charge for DDA&A will differ in subsequent years. Historically the Fund’s U.S. GAAP ceiling test write-downs have exceeded the Canadian GAAP write-downs. As a result, U.S. GAAP DDA&A charges are lower than Canadian GAAP DDA&A charges.

A U.S. GAAP difference also exists relating to the basis of measurement of proved reserves that is utilized in the depletion calculation. Under U.S. GAAP, depletion charges are calculated by reference to proved reserves estimated using constant prices. Under Canadian GAAP, depletion charges are calculated by reference to proved reserves estimated using future prices and costs.

For the year ended December 31, 2006, DDA&A calculated under U.S. GAAP was $74,391,000 ($52,542,000 net of tax) lower than DDA&A calculated under Canadian GAAP. For the year ended December 31, 2005, DDA&A calculated under U.S. GAAP was $57,050,000 ($37,659,000 net of tax) lower than DDA&A calculated under Canadian GAAP.


(b) Derivative Instruments and Hedging

Effective January 1, 2004, the Fund prospectively adopted CICA Accounting Guideline - 13 “Hedging Relationships” (“AcG-13”) and Emerging Issues Committee Abstract 128 “Accounting for Trading, Speculative or Non-hedging Derivative Financial Instruments”. As a result of this adoption, derivative financial instruments not designated as hedges receive the same treatment under both Canadian and U.S. GAAP. Upon adoption of AcG-13, deferred credits and deferred charges of $21,015,000 were recognized representing the fair value of derivative financial instruments in place as of January 1, 2004 that did not qualify for hedge accounting. These deferred charges were amortized over the life of the financial instruments for Canadian GAAP and were equal to the aggregate of U.S. GAAP gains and losses incurred on these instruments prior to January 1, 2004. During 2005, the remaining $3,143,000 ($2,074,000 net of tax) of the deferred charges were amortized to income resulting in a U.S. GAAP difference.

Under Canadian GAAP, disclosure of the fair value of derivative financial instruments that qualify for hedge accounting is required with no effect on assets, liabilities or net income. Under U.S. GAAP, all derivative instruments are recognized on the balance sheet as either an asset or liability measured at fair value. Changes in the fair value are recognized in earnings unless specific hedge criteria are met.

Cash Flow Hedges
Under U.S. GAAP changes in the fair value of derivatives that are designated as cash flow hedges are recognized in earnings in the same period as the hedged item. The effective portion of the change in fair value is recognized in other comprehensive income with any ineffectiveness recognized in net income.

A U.S. GAAP difference exists as the Fund’s certain interest rate and electricity swaps are designated as cash flow hedges under Canadian and U.S. GAAP.


 
Page 22 of 26
 
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Effective December 31, 2005 the Fund stopped designating commodity financial contracts as cash flow hedges in accordance with CICA AcG-13, “Hedging Relationships”. As a result of this change, a deferred credit and deferred financial asset of $49,874,000 were recognized representing the fair value of these financial contracts. The deferred asset was amortized to income during 2006 over the remaining term of the contracts. Under U.S. GAAP, the fair value these contracts was recorded on the balance sheet at fair value with the offset recorded in accumulated other comprehensive income as at December 31, 2005. The amount recognized in accumulated other comprehensive income will be reclassified to earnings in the same period as the corresponding gains or losses associated with the hedged item. In 2006, $49,874,000 was reclassified from accumulated other comprehensive income to earnings.

Fair Value Hedges
For derivative instruments designated as fair value hedges under U.S. GAAP, both the derivative instrument and the underlying commitment are recognized on the balance sheet at their fair value. The change in fair value of both items is reflected in earnings.

A U.S. GAAP difference exists as the Fund’s cross-currency and interest rate swap is designated as a fair value hedge under Canadian GAAP and U.S. GAAP.


(c) Interest Capitalization
U.S. GAAP requires interest cost to be capitalized for development projects that have not reached commercial production. A U.S. GAAP difference exists as there is not a similar requirement under Canadian GAAP. For the year ended December 31, 2006 the Fund capitalized interest of $3,436,000 ($2,431,000 net of tax) (2005 - nil) related to projects under development.


(d) Unit-based Compensation

On January 1, 2005 the Fund adopted Statement of Financial Accounting Standards (“SFAS”) 123R, “Share-Based Payment” using the modified prospective application of this standard and adopted the fair value method of accounting for all rights granted under the rights plan. In 2003 and 2004 the Fund accounted for the rights plan using the intrinsic method. As a result of this change, on January 1, 2005 the Fund recorded a trust unit rights liability of $12,208,000 which represented the fair value of all outstanding rights on that date, in proportion to the requisite service period rendered to that date. In addition, contributed surplus was reduced by $13,961,000, representing previously recognized compensation cost for all outstanding rights, and a recovery of $1,753,000 was recorded to cumulative effect of a change in accounting principle.

A U.S. GAAP difference exists as rights granted under our rights plan are considered liability awards for U.S. GAAP and equity awards under Canadian GAAP. The distinction between a liability award and an equity award has an impact on the related accounting treatment.

Under Canadian GAAP rights are accounted for using the fair value method for an equity award. Under this method, the fair value of the right is determined using a binomial lattice option-pricing model on the grant date and is not subsequently remeasured. This amount is charged to earnings over the vesting period of the rights, with a corresponding increase in contributed surplus. When rights are exercised, the fair value recorded in contributed surplus is recorded to unitholders’ capital.

Under U.S. GAAP rights are accounted for using the fair value method for a liability award. Under this method, the trust unit rights liability is calculated based on the rights fair value determined using a binomial lattice option-pricing model at each reporting date until the date of settlement. Compensation cost for each period is based on the change in the fair value of the rights for each reporting period. When rights are exercised, the proceeds, together with the amount recorded as a trust unit rights liability, are recorded to mezzanine equity.
 

 
Page 23 of 26

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The following assumptions were used to arrive at the estimate of fair value as at December 31 for each the respective years:

     
2006
    
2005
  
Dividend yield
    
9.53
%
  
8.85
%
Right’s exercise price reduction
  
$
1.67
  
$
1.49
  
Volatility
    
27.88
%
  
21.58
%
Risk-free interest rate
    
3.94
%
  
3.85
%
Forfeiture rate
    
2.80
%
  
4.60
%


The weighted average grant date fair value of trust unit rights granted in 2006 was $6.83 per trust unit right (2005 - $5.17). The total intrinsic value of trust unit rights exercised during 2006 was $14,900,000 (2005 - $14,300,000).

As at December 31, 2006, 809,000 trust unit rights were exercisable at a weighted average reduced exercise price of $39.81 with a weighted average remaining contractual term of 3.9 years, giving an aggregate intrinsic value of $9,700,000.

The following chart details the U.S. GAAP differences related to our trust unit rights plan for the years ended December 31, 2006 and 2005.

 
  
2006
2005
 
    
CDN GAAP
    
U.S. GAAP
    
Difference
    
CDN GAAP
    
U.S. GAAP
    
Difference
  
Compensation expense
  
$
6,323,000
  
$
8,560,000
  
$
2,237,000
  
$
3,040,000
  
$
22,772,000
  
$
19,732,000
  
Contributed Surplus
  
$
6,305,000
  
$
-
  
$
(6,305,000
)
$
3,047,000
  
$
-
  
$
(3,047,000
)
Trust unit rights liability
  
$
-
  
$
14,298,000
  
$
14,298,000
  
$
-
  
$
20,654,000
  
$
20,654,000
  


(e) Marketable Securities

Under Canadian GAAP the Fund accounts for its marketable securities using the cost method and only discloses the fair value.

Under U.S. GAAP marketable securities that have a readily determinable fair value are considered available for sale and are recorded on the balance sheet at fair value with changes in fair value recognized in comprehensive income.

As at December 31, 2006 available for sale marketable securities included in other current assets had a fair value of $16,758,000 (2005 - $21,713,000) and an amortized cost of $2,265,000 (2005 - $10,815,000), resulting in a gross unrealized holding gain of $14,493,000 (2005 - $10,898,000). Available for sale marketable securities included in other assets had a fair value of $13,231,000 (2005 - nil) and an amortized cost of $10,000,000 (2005 - nil), resulting in a gross unrealized holding gain of $3,231,000 (2005 - nil).

For the year ended December 31, 2006, the unrealized holding gain on available for sale securities included in accumulated other comprehensive income increased by $6,826,000 (2005 - $9,230,000).

For the year ended December 31, 2006, the Fund disposed of available for sale marketable securities for proceeds of $5,154,000 (2005 - $1,539,000) resulting in a gain of $1,425,000 (2005 - $1,158,000) being included in net income. The Fund uses the average cost method in computing realized gains or losses on sale of marketable securities.

Under U.S. GAAP securities whose fair value is not readily determinable, such as investments in private companies, are carried at cost. For the year ended December 31, 2006, the Fund had securities totaling $38,700,000 that were carried at cost (2005 - $5,440,000).

 
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(f) Unitholders’ Mezzanine Equity 

U.S. GAAP difference exists as a result of the redemption feature in the Fund’s trust units, which is required for the Fund to retain its Canadian mutual fund trust status. The trust units are redeemable at the option of the holder for approximately 85% of the current trading price. The amount of trust units that are redeemable for cash is limited to $500,000 in any two consecutive months. Any redemption in excess of the limit may be honored with promissory notes or other investments of the Fund. For Canadian GAAP, the trust units are considered to be permanent equity and are presented as unitholders’ capital. Under U.S. GAAP, the redemption feature of the trust units excludes them from classification as permanent equity and results in the trust units being classified as mezzanine equity.

For U.S. GAAP the Fund has recorded unitholders’ mezzanine equity in the amount of $5,305,098,000 for 2006 (2005 - $5,580,869,000), which represents the estimated redemption value of the trust units at 85% of the year-end market price. In addition, the Fund has recognized a deficit of $3,015,590,000 for 2006 (2005- $3,551,509,000) resulting from eliminating unitholders’ capital and replacing it with unitholders’ mezzanine equity at redemption value. Changes in unitholders’ mezzanine equity in excess of trust units issued, net of redemptions, net income and cash distributions in any period are recognized as charges to the deficit.

(g) Cumulative Translation Adjustment

A U.S. GAAP difference exists relating to the cumulative translation adjustment that is generated upon translating the financial statements of the Fund’s U.S. subsidiaries. For Canadian GAAP the cumulative translation adjustment is deferred and included as a separate component of equity. For U.S. GAAP this amount is recognized in comprehensive income.

The Fund’s comprehensive income for the year ended December 31, 2006 includes a net decrease in the cumulative translation adjustment of $6,589,000 (2005 - increase of $15,568,000).


(h) Additional Disclosures Required under U.S. GAAP

i. The components of accounts receivable are as follows:

As at December 31 ($ thousands)
    
2006
    
2005
  
Oil & Gas Sales and Accruals
  
$
111,049
  
$
117,853
  
Joint Venture
    
62,311
    
48,920
  
Other
    
3,552
    
5,070
  
Less: Allowance for Doubtful Accounts
    
(1,458
)
  
(1,220
)
   
$
175,454
  
$
170,623
  


ii. The components of accounts payable are as follows:

As at December 31 ($ thousands)
    
2006
    
2005
  
Contractors and Vendors
 
$
137,539
  
$
151,435
  
Accrued Liabilities
    
146,747
    
165,440
  
   
$
284,286
  
$
316,875
  


iii. Net Oil and Gas Sales

Under U.S. GAAP oil and gas sales are presented net of royalties.

For the year ended December 31 ($ thousands)
    
2006
    
2005
  
Oil and Gas Sales
  
$
1,595,324
  
$
1,550,569
  
Royalties
    
(293,161
)
  
(296,983
)
Net Oil and Gas Sales
  
$
1,302,163
  
$
1,253,586
  


 
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iv. Consolidated Cash Flows:

The consolidated statements of cash flows prepared in accordance with Canadian GAAP present operating cash flow before changes in non-cash working capital items. This total cannot be presented under U.S. GAAP.

The following chart details the changes in non-cash working capital:

($ thousands)
    
2006
    
2005
  
Accounts Receivable
  
$
(4,831
)
$
(62,627
)
Other current
    
20,036
    
(17,149
)
Accounts Payable
    
(32,589
)
  
137,307
  
Distributions Payable to Unitholders
    
2,356
    
12,924
  
Other
    
(472
)
  
(26,263
)
Total Change in non-cash working capital
  
$
(15,500
)
$
44,192
  
               
Relating to:
              
    Operating Activities
  
$
(14,321
)
$
(19,777
)
    Financing Activities
    
2,356
    
12,924
  
    Investing Activities
    
(3,535
)
  
51,045
  
   
$
(15,500
)
$
44,192
  


v. Business Combinations:

For our business combinations completed during 2005 U.S. GAAP requires supplemental information on a pro forma basis as though the business combinations had been completed at the beginning of the period. The Fund did not complete any business combinations during 2006.

The following unaudited pro forma results are based on U.S. GAAP revenues, net income and earnings per trust unit adjusted as if the respective business combinations occurred on January 1, 2005. These results are not necessarily indicative of actual results or future performance.
 
For the year ended December 31, 2005 ($ thousands)
    
Lyco
    
TriLoch
  
Revenues
  
$
1,267,385
  
$
1,167,788
  
Net Income
 
$
477,840
  
$
455,662
  
Earnings per trust unit - Basic ($/unit)
 
$
4.13
  
$
4.15
  
Earnings per trust unit - Diluted ($/unit)
 
$
4.12
  
$
4.14
  
 

U.S. Pronouncements

In September 2006 the Financial Accounting Standards Board (“FASB”) issued SFAS 157 - Fair Value Measurements. This statement defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. This statement is effective for fiscal years beginning after November 15, 2007. The Fund does not expect there to be a material impact on the Consolidated Financial Statements upon adoption of the Statement.

In June 2006 the FASB issued FASB Interpretation No. 48 - Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109. This guidance seeks to reduce the diversity in practice associated with certain aspects of the recognition and measurement related to accounting for income taxes. This interpretation is effective for fiscal years beginning after December 15, 2006. The Fund is in the process of assessing the impact of this Interpretation.

In February 2006 the FASB issued SFAS 155 - Accounting for certain hybrid financial instruments. This Statement amends SFAS 133 on derivatives and hedging and SFAS 140 on transfers and servicing of financial assets and extinguishments of liabilities. The Statement provides a fair value measurement option for certain hybrid financial instruments containing an embedded derivative that would otherwise require bifurcation. The Statement is effective for all instruments acquired, issued or subject to a re-measurement event occurring in years beginning after September 15, 2006. The Fund does not expect there to be a material impact on the Consolidated Financial Statements upon adoption of the Statement.
 
 
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