Exhibit 99.2
CONSOLIDATED FINANCIAL STATEMENTS AND
AUDITORS’ REPORT TO SHAREHOLDERS
For the Fiscal Year Ended December 31, 2007
Management’s Report
Managements’ Responsibility On Financial Statements
Management is responsible for the preparation of the accompanying consolidated financial statements and for the consistency therewith of all other financial and operating data presented in this annual report. The consolidated financial statements have been prepared in accordance with the accounting policies detailed in the notes thereto. In Management’s opinion, the consolidated financial statements are in accordance with Canadian generally accepted accounting principles, have been prepared within acceptable limits of materiality, and have utilized supportable, reasonable estimates.
To ensure the integrity of our financial statements, we carefully select and train qualified personnel. We also ensure our organizational structure provides appropriate delegation of authority and division of responsibilities. Our policies and procedures are communicated throughout the organization including a written ethics and integrity policy that applies to all employees including the chief executive officer and chief financial officer.
The Board of Directors approves the consolidated financial statements. Their financial statement related responsibilities are fulfilled mainly through the Audit Committee. The Audit Committee is composed entirely of independent directors, and includes at least one director with financial expertise. The Audit Committee meets regularly with management and the external auditors to discuss reporting and control issues and ensures each party is properly discharging its responsibilities. The Audit Committee also considers the independence of the external auditors and reviews their fees.
The consolidated financial statements have been audited by Deloitte & Touche LLP, independent auditors, in accordance with generally accepted auditing standards on behalf of the shareholders.
Management’s Report On Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining an adequate system of internal control over financial reporting. Internal control over financial reporting is a process designed to provide reasonable assurance that all assets are safeguarded, transactions are appropriately authorized and to facilitate the preparation of relevant, reliable and timely information. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Management has assessed the effectiveness of the Trust’s internal control over financial reporting as defined in Rule 13a-15 under the US Securities Exchange Act of 1934. The assessment was based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2007. The Trust’s internal control over financial reporting as of December 31, 2007 has been audited by Deloitte & Touche LLP, the Trust’s Independent Registered Chartered Accountants, who also audited the Trust’s consolidated financial statements for the year ended December 31, 2007.
/s/ “John P. Dielwart” |
| /s/ “Steven W. Sinclair” |
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John P. Dielwart |
| Steven W. Sinclair |
President and Chief Executive Officer |
| Senior Vice-President Finance and Chief Financial Officer |
Calgary, Alberta
February 8, 2008
1
Report of Independent Registered Chartered Accountants
TO THE BOARD OF DIRECTORS OF ARC RESOURCES LTD. AND UNITHOLDERS OF ARC ENERGY TRUST:
We have audited the internal control over financial reporting of ARC Energy Trust and subsidiaries (the “Trust”) as of December 31, 2007, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Trust’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, included in the accompanying Management Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Trust’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, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
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, the Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
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, 2007 of the Trust and our report dated February 8, 2008 expressed an unqualified opinion on those financial statements and included a separate report titled Comments by Independent Registered Chartered Accountants on Canada-United States of America Reporting Difference referring to changes in accounting principles.
/s/ “Deloitte & Touche LLP”
Independent Registered Chartered Accountants
Calgary, Canada
February 8, 2008
2
Comments by Independent Registered Chartered Accountants on
Canada-United States of America Reporting Difference
The standards of the Public Company Accounting Oversight Board (United States) require the addition of an explanatory paragraph (following the opinion paragraph) when there are changes in accounting principles that have a material effect on the comparability of the Trust’s financial statements, such as the changes described in Notes 3 and 22 to the consolidated financial statements. Although we conducted our audits in accordance with both Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), our report to the Board of Directors of ARC Resources Ltd. and Unitholders of ARC Energy Trust, dated February 8, 2008, is expressed in accordance with Canadian reporting standards which do not require a reference to such changes in accounting principles in the auditors’ report when the changes are properly accounted for and adequately disclosed in the financial statements.
/s/ “Deloitte & Touche LLP”
Independent Registered Chartered Accountants
Calgary, Canada
February 8, 2008
Report of Independent Registered Chartered Accountants
TO THE BOARD OF DIRECTORS OF ARC RESOURCES LTD. AND UNITHOLDERS OF ARC ENERGY TRUST:
We have audited the accompanying consolidated balance sheets of ARC Energy Trust and subsidiaries (the “Trust”) as at December 31, 2007 and 2006, and the related consolidated statements of income and deficit, comprehensive income and accumulated other comprehensive loss and cash flows for the years then ended. These financial statements are the responsibility of the Trust’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). These 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, these consolidated financial statements present fairly, in all material respects, the financial position of ARC Energy Trust and subsidiaries as at December 31, 2007 and 2006, and the results of their operations and their cash flows for the years then ended in accordance 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 Trust’s internal control over financial reporting as of December 31, 2007, 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 formerly February 8, 2008 expressed an unqualified opinion on the Trust’s internal control over financial reporting.
/s/ “Deloitte & Touche LLP”
Independent Registered Chartered Accountants
Calgary, Canada
February 8, 2008
3
Consolidated Balance Sheets
As at December 31
(CDN$ millions) |
| 2007 |
| 2006 |
| ||
Assets |
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Current assets |
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|
|
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Cash |
| $ | 7.0 |
| $ | 2.8 |
|
Accounts receivable |
| 162.5 |
| 129.8 |
| ||
Prepaid expenses |
| 15.0 |
| 18.4 |
| ||
Risk management contracts (Note 11) |
| 13.1 |
| 25.7 |
| ||
Future income taxes (Note 13) |
| 4.0 |
| — |
| ||
|
| 201.6 |
| 176.7 |
| ||
Reclamation funds (Note 5) |
| 26.1 |
| 30.9 |
| ||
Risk management contracts (Note 11) |
| 4.7 |
| — |
| ||
Property, plant and equipment (Note 6) |
| 3,143.0 |
| 3,093.8 |
| ||
Long-term investment (Note 7) |
| — |
| 20.0 |
| ||
Goodwill |
| 157.6 |
| 157.6 |
| ||
Total assets |
| $ | 3,533.0 |
| $ | 3,479.0 |
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Liabilities |
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Current liabilities |
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Accounts payable and accrued liabilities (Note 8) |
| $ | 180.6 |
| $ | 162.1 |
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Distributions payable |
| 42.1 |
| 40.9 |
| ||
Risk management contracts (Note 11) |
| 57.6 |
| 34.4 |
| ||
|
| 280.3 |
| 237.4 |
| ||
Risk management contracts (Note 11) |
| 28.2 |
| — |
| ||
Long-term debt (Note 9) |
| 714.5 |
| 687.1 |
| ||
Accrued long-term incentive compensation (Note 19) |
| 12.1 |
| 14.6 |
| ||
Asset retirement obligations (Note 10) |
| 140.0 |
| 177.3 |
| ||
Future income taxes (Note 13) |
| 316.2 |
| 434.2 |
| ||
Total liabilities |
| 1,491.3 |
| 1,550.6 |
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Commitments And Contingencies (Note 21) |
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Non-controlling Interest |
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Exchangeable shares (Note 14) |
| 43.1 |
| 40.0 |
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Unitholders’ Equity |
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Unitholders’ capital (Note 15) |
| 2,465.7 |
| 2,349.2 |
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Contributed surplus (Note 18) |
| 1.7 |
| 2.4 |
| ||
Deficit (Note 16) |
| (465.9 | ) | (463.2 | ) | ||
Accumulated other comprehensive loss (Notes 3 and 16) |
| (2.9 | ) | — |
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Total unitholders’ equity |
| 1,998.6 |
| 1,888.4 |
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Total liabilities and unitholders’ equity |
| $ | 3,533.0 |
| $ | 3,479.0 |
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See accompanying notes to the consolidated financial statements
4
Consolidated Statements Of Income And Deficit
For the years ended December 31
(CDN$ millions, except per unit amounts) |
| 2007 |
| 2006 |
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Revenues |
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Oil, natural gas, and natural gas liquids |
| $ | 1,251.6 |
| $ | 1,230.5 |
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Royalties |
| (219.4 | ) | (222.3 | ) | ||
|
| 1,032.2 |
| 1,008.2 |
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Gain (loss) gain on risk management contracts (Note 11) |
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Realized |
| 14.1 |
| 29.3 |
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Unrealized |
| (55.9 | ) | (4.6 | ) | ||
|
| 990.4 |
| 1,032.9 |
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Expenses |
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Transportation |
| 16.4 |
| 14.5 |
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Operating |
| 218.4 |
| 195.4 |
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General and administrative |
| 49.1 |
| 47.1 |
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Interest on long-term debt (Note 9) |
| 36.9 |
| 31.8 |
| ||
Depletion, depreciation and accretion (Notes 6 and 10) |
| 371.5 |
| 360.0 |
| ||
(Gain) loss on foreign exchange (Note 12) |
| (69.4 | ) | 4.2 |
| ||
|
| 622.9 |
| 653.0 |
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|
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Gain on sale of investment (Note 7) |
| 13.3 |
| — |
| ||
Capital and other taxes |
| — |
| (0.3 | ) | ||
Future income tax recovery (Note 13) |
| 121.3 |
| 87.1 |
| ||
Net income before non-controlling interest |
| 502.1 |
| 466.7 |
| ||
Non-controlling interest (Note 14) |
| (6.8 | ) | (6.6 | ) | ||
Net income |
| $ | 495.3 |
| $ | 460.1 |
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Deficit, beginning of year |
| $ | (463.2 | ) | $ | (439.1 | ) |
Distributions paid or declared (Note 17) |
| (498.0 | ) | (484.2 | ) | ||
Deficit, end of year (Note 16) |
| $ | (465.9 | ) | $ | (463.2 | ) |
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Net income per unit (Note 20) |
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Basic |
| $ | 2.39 |
| $ | 2.28 |
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Diluted |
| $ | 2.39 |
| $ | 2.27 |
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See accompanying notes to the consolidated financial statements
5
Consolidated Statements of Comprehensive Income
and Accumulated Other Comprehensive Loss
For the years ended December 31
($CDN millions) |
| 2007 |
| 2006 |
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Net income |
| $ | 495.3 |
| $ | 460.1 |
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Other comprehensive loss, net of tax |
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Loss on financial instruments designated as cash flow hedges (1) |
| (7.4 | ) | — |
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Gains and losses on financial instruments designated as cash flow hedges in prior periods realized in net income in the current year (2) |
| (0.3 | ) | — |
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Net unrealized losses on available-for-sale reclamation funds’ investments (3) |
| (0.1 | ) | — |
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Other comprehensive loss |
| (7.8 | ) | — |
| |||
Comprehensive income |
| $ | 487.5 |
| $ | 460.1 |
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Accumulated other comprehensive income, beginning of year |
| — |
| — |
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Application of initial adoption |
| 4.9 |
| — |
| |||
Other comprehensive loss |
| (7.8 | ) | — |
| |||
Accumulated other comprehensive loss, end of year (Note 16) |
| $ | (2.9 | ) | — |
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(1) Amount is net of tax recovery of $2.7 million for the year ended December 31, 2007.
(2) Amount is net of tax liability of $0.1 million for the year ended December 31, 2007.
(3) Nominal future income tax impact.
See accompanying notes to consolidated financial statements.
6
Consolidated Statements Of Cash Flows
For the years ended December 31
(CDN$ millions) |
| 2007 |
| 2006 |
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Cash Flows From Operating Activities |
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Net income |
| $ | 495.3 |
| $ | 460.1 |
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Add items not involving cash: |
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Non-controlling interest (Note 14) |
| 6.8 |
| 6.6 |
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Future income tax recovery (Note 13) |
| (121.3 | ) | (87.1 | ) | ||
Depletion, depreciation and accretion (Notes 6 and 10) |
| 371.5 |
| 360.0 |
| ||
Non-cash loss on risk management contracts (Note 11) |
| 55.9 |
| 4.6 |
| ||
Non-cash (gain) loss on foreign exchange (Note 12) |
| (69.6 | ) | 4.5 |
| ||
Non-cash trust unit incentive compensation (Notes 18 and 19) |
| 3.5 |
| 11.9 |
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Gain on sale of investment (Note 7) |
| (13.3 | ) | — |
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Expenditures on site restoration and reclamation (Note 10) |
| (18.2 | ) | (10.6 | ) | ||
Change in non-cash working capital |
| (5.7 | ) | (16.0 | ) | ||
|
| 704.9 |
| 734.0 |
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Cash Flows From Financing Activities |
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Issuance of long-term debt under revolving credit facilities, net |
| 104.2 |
| 162.7 |
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Repayment of senior secured notes |
| (5.8 | ) | (6.8 | ) | ||
Issue of trust units |
| 3.7 |
| 14.4 |
| ||
Trust unit issue costs |
| — |
| (0.2 | ) | ||
Cash distributions paid (Note 17) |
| (388.4 | ) | (389.6 | ) | ||
Payment of retention bonuses |
| (1.0 | ) | (1.0 | ) | ||
Change in non-cash working capital |
| 0.4 |
| — |
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|
| (286.9) |
| (220.5 | ) | ||
Cash Flows From Investing Activities |
|
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Corporate acquisitions, net of cash received (Note 4) |
| — |
| (16.6 | ) | ||
Acquisition of petroleum and natural gas properties |
| (43.7 | ) | (117.4 | ) | ||
Proceeds on disposition of petroleum and natural gas properties |
| 1.2 |
| 2.1 |
| ||
Capital expenditures |
| (396.5 | ) | (362.7 | ) | ||
Long-term investment (Note 7) |
| 33.3 |
| (20.0 | ) | ||
Net reclamation fund withdrawals (contributions) (Note 5) |
| 4.7 |
| (7.4 | ) | ||
Change in non-cash working capital |
| (12.8 | ) | 11.3 |
| ||
|
| (413.8 | ) | (510.7 | ) | ||
Increase in Cash |
| 4.2 |
| 2.8 |
| ||
Cash, Beginning of Year |
| 2.8 |
| — |
| ||
Cash, End of Year |
| $ | 7.0 |
| $ | 2.8 |
|
See accompanying notes to the consolidated financial statements
7
Notes to the Consolidated Financial Statements
December 31, 2007 and 2006
(all tabular amounts in CDN$ millions, except per unit and volume amounts)
1. Structure of the Trust
ARC Energy Trust (the “Trust”) was formed on May 7, 1996 pursuant to a Trust indenture (the “Trust Indenture”) that has been amended from time to time, most recently on May 15, 2006. Computershare Trust Company of Canada was appointed as Trustee under the Trust Indenture. The beneficiaries of the Trust are the holders of the Trust units.
The Trust was created for the purposes of issuing Trust units to the public and investing the funds so raised to purchase a royalty in the properties of ARC Resources Ltd. (“ARC Resources”) and ARC Oil & Gas Fund (“ARC Oil & Gas”). The Trust Indenture was amended on June 7, 1999 to convert the Trust from a closed-end to an open-ended investment Trust. The current business of the Trust includes the investment in all types of energy business-related assets including, but not limited to, petroleum and natural gas-related assets, gathering, processing and transportation assets. The operations of the Trust consist of the acquisition, development, exploitation and disposition of these assets and the distribution of the net cash proceeds from these activities to the unitholders.
2. Summary of Accounting Policies
The consolidated financial statements have been prepared by management following Canadian generally accepted accounting principles (“GAAP”). These principles differ in certain respects from accounting principles generally accepted in the United States of America (“US GAAP”) and to the extent that they affect the Trust, these differences are described in Note 22. The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingencies at the date of the financial statements, and revenues and expenses during the reporting year. Actual results could differ from those estimated.
In particular, the amounts recorded for depletion, depreciation and accretion of the petroleum and natural gas properties and for asset retirement obligations are based on estimates of reserves and future costs. By their nature, these estimates, and those related to future cash flows used to assess impairment, are subject to measurement uncertainty and the impact on the financial statements of future periods could be material.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Trust and its subsidiaries. Any reference to “the Trust” throughout these consolidated financial statements refers to the Trust and its subsidiaries. All inter-entity transactions have been eliminated.
REVENUE RECOGNITION
Revenue associated with the sale of crude oil, natural gas, and natural gas liquids (NGLs) owned by the Trust are recognized when title passes from the Trust to its customers.
TRANSPORTATION
Costs paid by the Trust for the transportation of natural gas, crude oil and NGLs from the wellhead to the point of title transfer are recognized when the transportation is provided.
JOINT VENTURE
The Trust conducts many of its oil and gas production activities through joint ventures and the financial statements reflect only the Trust’s proportionate interest in such activities.
8
DEPLETION AND DEPRECIATION
Depletion of petroleum and natural gas properties and depreciation of production equipment are calculated on the unit-of-production basis based on:
(a) total estimated proved reserves calculated in accordance with National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities;
(b) total capitalized costs, excluding undeveloped lands, plus estimated future development costs of proved undeveloped reserves, including future estimated asset retirement costs; and
(c) relative volumes of petroleum and natural gas reserves and production, before royalties, converted at the energy equivalent conversion ratio of six thousand cubic feet of natural gas to one barrel of oil.
UNIT BASED COMPENSATION
The Trust established a Trust Unit Incentive Rights Plan (the “Rights Plan”) for employees, independent directors and long-term consultants who otherwise meet the definition of an employee of the Trust. The exercise price of the rights granted under the Plan may be reduced in future periods in accordance with the terms of the Plan. The Trust accounts for the rights using the fair value method, whereby the fair value of rights is determined on the date on which fair value can initially be determined. The fair value is then recorded as compensation expense over the period that the rights vest, with a corresponding increase to contributed surplus. When rights are exercised, the proceeds, together with the amount recorded in contributed surplus, are recorded to unitholders’ capital.
WHOLE TRUST UNIT INCENTIVE PLAN COMPENSATION
The Trust has established a Whole Trust Unit Incentive Plan (the “Whole Unit Plan”) for employees, independent directors and long-term consultants who otherwise meet the definition of an employee of the Trust. Compensation expense associated with the Whole Unit Plan is granted in the form of Restricted Trust Units (“RTUs”) and Performance Trust Units (“PTUs”) and is determined based on the intrinsic value of the Whole Trust Units at each period end. The intrinsic valuation method is used as participants of the Whole Unit Plan receive a cash payment on a fixed vesting date. This valuation incorporates the period end Trust unit price, the number of RTUs and PTUs outstanding at each period end, and certain management estimates. As a result, large fluctuations, even recoveries, in compensation expense may occur due to changes in the underlying Trust unit price. In addition, compensation expense is amortized and recognized in earnings over the vesting period of the Whole Unit Plan with a corresponding increase or decrease in liabilities. Classification between accrued liabilities and other long-term liabilities is dependent on the expected payout date.
The Trust charges amounts relating to head office employees to general and administrative expense, amounts relating to field employees to operating expense and amounts relating to geologists and geophysicists to property, plant and equipment.
The Trust has not incorporated an estimated forfeiture rate for RTUs and PTUs that will not vest. Rather, the Trust accounts for actual forfeitures as they occur.
CASH EQUIVALENTS
Cash equivalents include short-term investments, such as money market deposits or similar type instruments, with an original maturity of three months or less when purchased.
RECLAMATION FUNDS
Reclamation funds hold investment grade assets and cash and cash equivalents. In accordance with Section 3855, investments are categorized as either held-to-maturity or available-for-sale assets, which are initially measured at fair value. Held-to-maturity investments are subsequently measured at amortized cost using the effective interest method. Available-for-sale investments are subsequently measured at fair value with changes in fair value recognized in other comprehensive income, net of tax. Section 3855 became effective January 1, 2007 as described in Note 3.
Investments carried at amortized cost are subject to impairment losses in the event of a non-temporary decline in market value.
9
PROPERTY, PLANT AND EQUIPMENT (“PP&E”)
The Trust follows the full cost method of accounting. All costs of exploring, developing and acquiring petroleum and natural gas properties, including asset retirement costs, are capitalized and accumulated in one cost centre as all operations are in Canada. Maintenance and repairs are charged against income, and renewals and enhancements that extend the economic life of the PP&E are capitalized. Gains and losses are not recognized upon disposition of petroleum and natural gas properties unless such a disposition would alter the rate of depletion by 20 per cent or more.
IMPAIRMENT
The Trust places a limit on the aggregate carrying value of PP&E, which may be amortized against revenues of future periods.
Impairment is recognized if the carrying amount of the PP&E exceeds the sum of the undiscounted cash flows expected to result from the Trust’s proved reserves. Cash flows are calculated based on third party quoted forward prices, adjusted for the Trust’s contract prices and quality differentials.
Upon recognition of impairment, the Trust would then measure the amount of impairment by comparing the carrying amounts of the PP&E to an amount equal to the estimated net present value of future cash flows from proved plus risked probable reserves. The Trust’s risk-free interest rate is used to arrive at the net present value of the future cash flows. Any excess carrying value above the net present value of the Trust’s future cash flows would be recorded as a permanent impairment and charged against net income.
The cost of unproved properties is excluded from the impairment test described above and subject to a separate impairment test. In the case of impairment, the book value of the impaired properties is moved to the petroleum and natural gas depletable base.
GOODWILL
The Trust must record goodwill relating to a corporate acquisition when the total purchase price exceeds the fair value for accounting purposes of the net identifiable assets and liabilities of the acquired company. The goodwill balance is assessed for impairment annually at year-end or as events occur that could result in an impairment. Impairment is recognized based on the fair value of the reporting entity (consolidated Trust) compared to the book value of the reporting entity. If the fair value of the consolidated Trust is less than the book value, impairment is measured by allocating the fair value of the consolidated Trust to the identifiable assets and liabilities as if the Trust had been acquired in a business combination for a purchase price equal to its fair value. The excess of the fair value of the consolidated trust over the amounts assigned to the identifiable assets and liabilities is the fair value of the goodwill. Any excess of the book value of goodwill over this implied fair value of goodwill is the impairment amount. Impairment is charged to earnings in the period in which it occurs.
Goodwill is stated at cost less impairment and is not amortized.
ASSET RETIREMENT OBLIGATIONS
The Trust recognizes an Asset Retirement Obligation (“ARO”) in the period in which it is incurred when a reasonable estimate of the fair value can be made. On a periodic basis, management will review these estimates and changes, if any, to the estimate will be applied on a prospective basis. The fair value of the estimated ARO is recorded as a long-term liability, with a corresponding increase in the carrying amount of the related asset. The capitalized amount is depleted on a unit-of-production basis over the life of the reserves. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to earnings in the period. Revisions to the estimated timing of cash flows or to the original estimated undiscounted cost would also result in an increase or decrease to the ARO. Actual costs incurred upon settlement of the ARO are charged against the ARO to the extent of the liability recorded.
10
INCOME TAXES
The Trust 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 Trust and the Trust’s corporate subsidiaries and their respective tax base, using substantively enacted future income tax rates. The effect of a change in income tax rates on future tax liabilities and assets is recognized in income in the period in which the change occurs. Temporary differences arising on acquisitions result in future income tax assets and liabilities.
BASIC AND DILUTED PER TRUST UNIT CALCULATIONS
Basic net income per unit is computed by dividing the net income by the weighted average number of trust units outstanding during the period. Diluted net income per unit amounts are calculated based on net income before non-controlling interest divided by dilutive trust units. Dilutive trust units are arrived at by taking weighted average trust units and trust units issuable on conversion of exchangeable shares, and giving effect to the potential dilution that would occur if rights were exercised at the beginning of the period. The treasury stock method assumes that proceeds received from the exercise of in-the-money rights and the unrecognized trust unit incentive compensation are used to repurchase units at the average market price.
DERIVATIVE FINANCIAL INSTRUMENTS
The Trust is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of operations. A variety of derivative instruments are used by the Trust to reduce its exposure to fluctuations in commodity prices, foreign exchange rates, and interest rates. The fair values of these derivative instruments are based on an estimate of the amounts that would have been received or paid to settle these instruments prior to maturity. The Trust considers all of these transactions to be effective economic hedges, however, the majority of the Trust’s contracts do not qualify or have not been designated as effective hedges for accounting purposes.
For transactions that do not qualify for hedge accounting, the Trust applies the fair value method of accounting by recording an asset or liability on the Consolidated Balance Sheet and recognizing changes in the fair value of the instruments in the statement of income for the current period.
For derivative instruments that do qualify as effective accounting hedges, policies and procedures are in place to ensure that the required documentation and approvals are in place. This documentation specifically ties the derivative financial instruments to their use, and in the case of commodities, to the mitigation of market price risk associated with cash flows expected to be generated. When applicable, the Trust also identifies all relationships between hedging instruments and hedged items, as well as its risk management objective and the strategy for undertaking hedge transactions. This would include linking the particular derivative to specific assets and liabilities on the Consolidated Balance Sheet or to specific firm commitments or forecasted transactions. Where specific hedges are executed, the Trust assesses, both at the inception of the hedge and on an ongoing basis, whether the derivative used in the particular hedging transaction is effective in offsetting changes in fair value or cash flows of the hedged item. For accounting treatment of gains or losses on derivative instruments that qualify as effective accounting hedges refer to Note 3 – Hedges.
FOREIGN CURRENCY TRANSLATION
Monetary assets and liabilities denominated in a foreign currency are translated at the rate of exchange in effect at the Consolidated Balance Sheet date. Revenues and expenses are translated at the period average rates of exchange. Translation gains and losses are included in income in the period in which they arise.
11
NON-CONTROLLING INTEREST
The Trust must record non-controlling interest when exchangeable shares issued by a subsidiary of the Trust are transferable to third parties. Non-controlling interest on the Consolidated Balance Sheet is recognized based on the fair value of the exchangeable shares upon issuance plus the accumulated earnings attributable to the non-controlling interest. Net income is reduced for the portion of earnings attributable to the non-controlling interest. As the exchangeable shares are converted to Trust units, the non-controlling interest on the Consolidated Balance Sheet is reduced by the cumulative book value of the exchangeable shares and Unitholders’ capital is increased by the corresponding amount.
3. New Accounting Policies
Effective January 1, 2007, the Trust adopted six new accounting standards that were issued by the Canadian Institute of Chartered Accountants (“CICA”): Handbook Section 1530, Comprehensive Income, Section 3855, Financial Instruments – Recognition and Measurement, Section 3861, Financial Instruments – Disclosure and Presentation, Section 3865, Hedges, Section 3251, Equity and Section 1506, Accounting Changes. These new accounting standards have been adopted prospectively and, accordingly, comparative amounts for prior periods have not been restated. The standards provide requirements for the recognition, measurement and disclosure of financial instruments, the use of hedge accounting and the presentation of equity.
COMPREHENSIVE INCOME
Section 1530 introduces Comprehensive Income, which consists of Net Income and Other Comprehensive Income (Loss) (“OCI”). Comprehensive Income includes changes in Unitholders’ Equity from transactions and other events with non-owner sources, and OCI includes unrealized gains and losses on financial assets classified as available-for-sale and changes in the fair value of the effective portion of cash flow hedging instruments that qualify for hedge accounting. These items are excluded from Net Income calculated in accordance with GAAP. The Consolidated Statements of Comprehensive Income includes Accumulated Other Comprehensive Income (Loss) (“AOCI”), and the changes in these items during the year ended December 31, 2007. Cumulative changes in OCI are included in AOCI, which is presented as a new category within Unitholders’ Equity on the Consolidated Balance Sheet.
FINANCIAL INSTRUMENTS – RECOGNITION AND MEASUREMENT
Section 3855 establishes standards for recognizing and measuring financial assets, financial liabilities and non-financial derivatives. Under this standard, all financial instruments are required to be measured at fair value on initial recognition. Measurement in subsequent periods depends on whether the financial instrument has been classified as held-for-trading, available-for-sale, held-to-maturity, loans and receivables, or other financial liabilities.
a. Held-for-trading
Financial assets and liabilities designated as held-for-trading are subsequently measured at fair value with changes in those fair values recognized immediately in Net Income. With the exception of risk management contracts that qualify for hedge accounting, the Trust classifies all risk management contracts as held-for-trading. Cash is also classified as held-for-trading.
b. Available-for-sale assets
Available-for-sale financial assets are subsequently measured at fair value with changes in fair value recognized in OCI, net of tax. Amounts recognized in OCI for available-for-sale financial assets are transferred to net income when the asset is derecognized or when there is an other than temporary asset impairment. A portion of the Trust’s reclamation fund is classified as available-for-sale financial assets.
c. Held-to-maturity investments, loans and receivables and other financial liabilities
Held-to-maturity investments, loans and receivables, and other financial liabilities are subsequently measured at amortized cost using the effective interest method. The Trust classifies a portion of its reclamation fund investments to held-to-maturity, accounts receivables to loans and receivables, and accounts payable, distributions payable and long-term debt to other financial liabilities.
The Section allows an entity to designate any financial instrument as held-for-trading, which by characteristic and intended use may be classified under another category. The Trust has chosen not to make any such designations.
12
Transaction costs are expensed as incurred for financial instruments excluding long-term debt. The Trust has elected to capitalize costs incurred relating to debt issuances and to amortize these costs over the term of the associated debt using the effective interest rate method.
The Trust has elected January 1, 2003 as the effective date to identify and measure embedded derivatives in financial and non-financial contracts that are not closely related to the host contracts. No adjustments were required for embedded derivatives on adoption of this standard.
FINANCIAL INSTRUMENTS – DISCLOSURE AND PRESENTATION
Section 3861 establishes standards for enhancing financial statement users’ understanding of the significance of financial instruments to an entity’s financial position, performance and cash flows. It establishes standards for presentation of financial instruments and non-financial derivatives, and identifies the information that should be disclosed about them. This section sets forth standards on the presentation and classification of financial instruments between liabilities and equity, the classification of related interest, dividends, losses and gains, and the circumstances in which financial assets and liabilities are offset. The standard outlines required disclosures surrounding factors that affect the amount, timing and certainty of an entity’s future cash flows relating to financial instruments. Disclosure of information about the nature and extent of an entity’s use of financial instruments, the business purposes they serve, the risks associated with them and management’s policies for controlling those risks are also required.
HEDGES
Section 3865 specifies the criteria that must be satisfied in order for hedge accounting to be applied and the accounting for fair value and cash flow hedges. Hedge accounting is discontinued prospectively when the derivative no longer qualifies as an effective hedge, or the derivative is terminated or sold, or upon the sale or early termination of the hedged item. The Trust has currently designated its financial electricity contracts and treasury rate lock contracts as effective cash flow hedges. The Trust assesses, both at the inception of the hedge and on an ongoing basis, whether the derivative used in the particular hedging transaction is effective in offsetting changes in cash flows of the hedged item.
In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is recognized in OCI while the ineffective portion is recognized in Net Income. When hedge accounting is discontinued, the amounts previously recognized in AOCI are reclassified to Net Income during the periods when the variability in the cash flows of the hedged item affects Net Income. Gains and losses on derivatives are reclassified immediately to Net Income when the hedged item is sold or early terminated.
When hedge accounting is applied to a derivative used to hedge an anticipated transaction and it is determined that the anticipated transaction will not occur within the originally specified time period, hedge accounting is discontinued and the unrealized gains and losses are reclassified from AOCI to Net Income.
EQUITY
Section 3251 establishes standards for the presentation of equity and changes in equity during the reporting period. This section specifies that changes in equity for the period arising from Net Income, OCI, other changes in deficit, changes in contributed surplus, and changes in unitholders’ capital must be presented separately.
IMPACT
As a result of these changes in accounting policies, on January 1, 2007 the Trust recorded $4.9 million to application of initial adoption in AOCI to reflect the opening fair value of its cash flow hedges, net of tax, which was previously not recorded on the consolidated financial statements. The Trust has also recorded an increase of $7 million to its risk management asset and an increase of $2.1 million to its future income tax liability.
13
ACCOUNTING CHANGES
Section 1506 permits voluntary changes in accounting policy only if they result in financial statements that provide more reliable and relevant information. Changes in policy are applied retrospectively unless it is impractical to determine the period or cumulative impact of the change. Corrections of prior period errors are applied retrospectively and changes in accounting estimates are applied prospectively by including these changes in Net Income. In addition, disclosure is required for all future accounting changes when an entity has not applied a new source of GAAP that has been issued but is not yet effective.
FUTURE ACCOUNTING CHANGES
On December 1, 2006, the CICA issued three new accounting standards: Section 1535, Capital Disclosures, Section 3862, Financial Instruments – Disclosures, and Section 3863, Financial Instruments – Presentation. These new standards will be effective on January 1, 2008.
Section 1535 specifies the disclosure of an entity’s objectives, policies and processes for managing capital, quantitative data about what the entity regards as capital, whether the entity has complied with any capital requirements, and if it has not complied, the consequences of such non-compliance. This Section is expected to have minimal impact on the Trust’s financial statements.
Sections 3862 and 3863 specify standards of presentation and enhanced disclosures on financial instruments. These Sections will require the Trust to increase disclosure on the nature and extent of risks arising from financial instruments and how the entity manages those risks.
In February 2008, the CICA issued Section 3064, Goodwill and Intangible Assets, replacing Section 3062, Goodwill and Other Intangible Assets and Section 3450, Research and Development Costs. The new Section will be effective on January 1, 2009. Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets subsequent to its initial recognition. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. The Trust is currently evaluating the impact of the adoption of this new Section, however does not expect a material impact on its consolidated financial statements.
4. Corporate Acquisitions
On December 6, 2006 the Trust completed a minor corporate acquisition for net cash consideration of $16.6 million. There was no goodwill recognized with this acquisition. Substantially all of the consideration was applied against property, plant and equipment, with a nominal amount applied against working capital items.
5. Reclamation Funds
|
| December 31, 2007 |
| December 31, 2006 |
| ||||||||
|
| Unrestricted |
| Restricted |
| Unrestricted |
| Restricted |
| ||||
Balance, beginning of year |
| $24.8 |
|
| $6.1 |
|
| $23.5 |
|
| $— |
|
|
Contributions |
| 6.2 |
|
| 5.9 |
|
| 6.0 |
|
| 6.1 |
|
|
Reimbursed expenditures (1) |
| (17.5 | ) |
| (0.6 | ) |
| (5.7 | ) |
| — |
|
|
Interest earned on funds |
| 1.1 |
|
| 0.3 |
|
| 1.0 |
|
| — |
|
|
Net unrealized losses on available-for-sale investments |
| (0.2 | ) |
| — |
|
| — |
|
| — |
|
|
Balance, end of year (2) |
| $14.4 |
|
| $11.7 |
|
| $24.8 |
|
| $6.1 |
|
|
(1) Amount differs from actual expenditures incurred by the Trust due to timing differences and discretionary reimbursements.
(2) As at December 31, 2007 the unrestricted reclamation fund held $1.5 million in cash and cash equivalents ($15 million at December 31, 2006), with the balance held in investment grade assets.
14
An unrestricted reclamation fund was established to fund future asset retirement obligation costs. In addition, the Trust has created a restricted reclamation fund associated with the Redwater property acquired in 2005. Contributions to the restricted and unrestricted reclamation funds and interest earned on the balances have been deducted from the cash distributions to the unitholders. The Board of Directors of ARC Resources has approved voluntary contributions to the unrestricted reclamation fund over a 20-year period that currently results in minimum annual contributions of $6 million ($6 million in 2006) based upon properties owned as at December 31, 2007. Contributions to the restricted reclamation fund will vary over time and have been disclosed in Note 21. Contributions for both funds are continually reassessed to ensure that the funds are sufficient to finance the majority of future abandonment obligations. Interest earned on the funds is retained within the funds.
For the year ended December 31, 2007 no amounts relating to available-for-sale reclamation fund assets were classified from accumulated other comprehensive loss into the statement of income.
6. Property, Plant and Equipment
|
| 2007 |
| 2006 |
| ||
Property, plant and equipment, at cost |
| $ | 5,065.0 |
| $ | 4,655.3 |
|
Accumulated depletion and depreciation |
| (1,922.0 | ) | (1,561.5 | ) | ||
Property, plant and equipment, net |
| $ | 3,143.0 |
| $ | 3,093.8 |
|
The calculation of 2007 depletion and depreciation included an estimated $549 million ($547 million in 2006) for future development costs associated with proved undeveloped reserves and excluded $173.7 million ($108.9 million in 2006) for the book value of unproved properties.
The Trust performed a ceiling test calculation at December 31, 2007 to assess the recoverable value of property plant and equipment (PP&E). Based on the calculation, the value of future net revenues from the Trust’s reserves exceeded the carrying value of the Trust’s PP&E at December 31, 2007. The benchmark prices used in the calculation were as follows:
|
| WTI Oil |
| AECO Gas |
|
|
|
Year ($US/bbl) |
| (CDN$/mmbtu) |
| Exchange Rates |
| USD/CAD |
|
2008 |
| 92.00 |
| 6.75 |
| 1.00 |
|
2009 |
| 88.00 |
| 7.55 |
| 1.00 |
|
2010 |
| 84.00 |
| 7.60 |
| 1.00 |
|
2011 |
| 82.00 |
| 7.60 |
| 1.00 |
|
2012 |
| 82.00 |
| 7.60 |
| 1.00 |
|
2013 |
| 82.00 |
| 7.60 |
| 1.00 |
|
2014 |
| 82.00 |
| 7.80 |
| 1.00 |
|
2015 |
| 82.00 |
| 7.97 |
| 1.00 |
|
2016 |
| 82.02 |
| 8.14 |
| 1.00 |
|
2017 |
| 83.66 |
| 8.31 |
| 1.00 |
|
2018 |
| 85.33 |
| 8.48 |
| 1.00 |
|
Remainder (1) |
| 2.0 | % | 2.0 | % | 1.00 |
|
(1) Percentage change represents the change in each year after 2018 to the end of the reserve life.
7. Long-term Investment
During the year the Trust sold its equity investment in a private oil sands company for proceeds of $33.3 million, resulting in a gain on sale of investment of $13.3 million. The original investment was purchased in 2006 for $20 million. The investment in the shares of the private company was considered to be a related party transaction due to common directorships of the Trust, the private company and the manager of a private equity fund that held shares in the private company. In addition, certain directors and officers of the Trust had minor direct and indirect shareholdings in the private company.
15
8. Accounts Payable and Accrued Liabilities
|
| 2007 |
| 2006 |
| ||
Trade accounts payable |
| $32.5 |
|
| $39.0 |
|
|
Accrued liabilities |
| 127.7 |
|
| 108.8 |
|
|
Current portion of accrued long-term incentive compensation |
| 18.2 |
|
| 11.5 |
|
|
Interest payable |
| 2.2 |
|
| 1.8 |
|
|
Retention bonuses |
| — |
|
| 1.0 |
|
|
Total accounts payable and accrued liabilities |
| $180.6 |
|
| $162.1 |
|
|
The current portion of accrued long-term incentive compensation represents the current portion of the Trust’s estimated liability for the Whole Unit Plan as at December 31, 2007 (see Note 19). This amount is payable in 2008.
9. Long-term Debt
|
| 2007 |
| 2006 |
| ||
Revolving credit facilities |
|
|
|
|
|
|
|
Syndicated credit facility – CDN denominated |
| $344.9 |
|
| $196.6 |
|
|
Syndicated credit facility – US denominated |
| 154.1 |
|
| 228.4 |
|
|
Working capital facility |
| — |
|
| 1.1 |
|
|
Senior secured notes |
|
|
|
|
|
|
|
5.42% USD Note |
| 74.1 |
|
| 87.4 |
|
|
4.94% USD Note |
| 17.8 |
|
| 28.0 |
|
|
4.62% USD Note |
| 61.8 |
|
| 72.8 |
|
|
5.10% USD Note |
| 61.8 |
|
| 72.8 |
|
|
Total long-term debt outstanding |
| $714.5 |
|
| $687.1 |
|
|
REVOLVING CREDIT FACILITIES
During 2007, the Trust renewed its $800 million secured, annually extendible, financial covenant-based three year syndicated credit facility. The revolving credit facility’s security is in the form of a floating charge on all lands and assignments and a negative pledge on petroleum and natural gas properties. The Trust also has in place a $25 million demand working capital facility.
Borrowings under the credit facility bear interest at bank prime (six per cent at December 31, 2007 and December 31, 2006) or, at the Trust’s option, Canadian dollar bankers’ acceptances or U.S. dollar LIBOR loans, plus a stamping fee. At the option of the Trust, the lenders will review the credit facility each year and determine whether they will extend the revolving period for another year. In the event that the credit facility is not extended at anytime before the maturity date, the loan balance will become repayable on the maturity date. The maturity date of the current credit facility is April 15, 2010. All drawings under the facility are subject to stamping fees that vary between 60 bps and 110 bps depending on certain consolidated financial ratios.
The working capital facility allows for maximum borrowings of $25 million and is due and payable immediately upon demand by the bank. The facility is secured and is subject to the same covenants as the syndicated credit facility.
5.42 PER CENT AND 4.94 PER CENT SENIOR SECURED USD NOTES
These senior secured notes were issued in two separate issues pursuant to an Uncommitted Master Shelf Agreement. The US$18 million senior secured notes were issued in 2002, bear interest at 4.94 per cent, have a remaining final term of 2.8 years (remaining average term of 1.8 years) and require equal principal repayments of US$6 million over a three year period commencing in 2008. The US$75 million senior secured notes were issued in 2005, bear interest at 5.42 per cent, have a remaining final term of 10 years (remaining weighted average term of 6.6 years) and require equal principal repayments over an eight year period commencing in 2010.
16
4.62 PER CENT AND 5.10 PER CENT SENIOR SECURED USD NOTES
These notes were issued on April 27, 2004 via a private placement in two tranches of US$62.5 million each. The first tranche of US$62.5 million bears interest at 4.62 per cent and has a remaining final term of 6.3 years (remaining weighted average term of 3.9 years) and require equal principal repayments over a six year period commencing 2009. Immediately following the issuance, the Trust entered into interest rate swap contracts that changed the interest rate from fixed to floating (see Note 11). The second tranche of US$62.5 million bears interest at 5.10 per cent and has a remaining final term of 8.3 years (remaining weighted average term of 6.4 years). Repayments of the notes will occur over a five year period commencing in 2012.
DEBT COVENANTS
The following are the significant financial covenants governing the revolving credit facilities:
· Long-term debt and letters of credit not to exceed three times annualized net income before non-cash items and interest expense;
· Long-term debt, letters of credit, and subordinated debt not to exceed four times annualized net income before non-cash items and interest expense; and
· Long-term debt and letters of credit not to exceed 50 per cent of unitholders’ equity and long-term debt, letters of credit, and
subordinated debt.
In the event that the Trust enters into a material acquisition whereby the purchase price exceeds 10 per cent of the book value of the Trust’s assets, the ratios in the first two covenants above are increased to 3.5 and 5.5 times respectively, while the third covenant is increased to 55 per cent for the subsequent six month period. As at December 31, 2007, the Trust had $4.8 million in letters of credit ($4.7 million in 2006), no subordinated debt, and was in compliance with all covenants.
The payment of principal and interest are allowable deductions in the calculation of cash available for distribution to unitholders and rank ahead of cash distributions payable to unitholders. Should the properties securing this debt generate insufficient revenue to repay the outstanding balances, the unitholders have no direct liability.
During 2007, the weighted-average effective interest rate under the credit facility was 5.5 per cent (5.3 per cent in 2006).
Amounts due under the working capital facility and the senior secured notes in the next 12 months have not been included in current liabilities as management has the ability and intent to refinance this amount through the syndicated credit facility.
Interest paid during 2007 was $1.8 million less than interest expense. The difference between interest paid and interest expense in 2006 was nominal.
10. Asset Retirement Obligations
The total future asset retirement obligations were estimated by management based on the Trust’s net ownership interest in all wells
and facilities, estimated costs to reclaim and abandon the wells and facilities and the estimated timing of the costs to be incurred
in future periods. The Trust has estimated the net present value of its total asset retirement obligations to be $140 million as at
December 31, 2007 ($177.3 million in 2006) based on a total future undiscounted liability of $1.29 billion ($1.04 billion in 2006). At December 31, 2007 management estimates that these payments are expected to be made over the next 51 years with the bulk of payments being made in years 2048 to 2058. At December 31, 2006 management had estimated that the expenditures would be made over 61 years with the bulk of payments being made in years 2017 to 2021 and 2057 to 2067. The Trust’s weighted average credit adjusted risk free rate of 6.6 per cent (6.5 per cent in 2006) and an inflation rate of 2.0 per cent (2.0 per cent in 2006) were used to calculate the present value of the asset retirement obligations. During the year, no gains or losses were recognized on settlements of asset retirement obligations.
17
The following table reconciles the Trust’s asset retirement obligations:
|
| 2007 |
| 2006 |
| ||||
Balance, beginning of year |
| $ | 177.3 |
| $ | 165.1 |
| ||
Increase in liabilities relating to corporate acquisitions |
| — |
| 4.9 |
| ||||
Increase in liabilities relating to development activities |
| 3.8 |
| 2.8 |
| ||||
(Decrease) increase in liabilities relating to change in estimate |
| (34.4 | ) | 4.0 |
| ||||
Settlement of liabilities during the year |
| (18.2 | ) | (10.6 | ) | ||||
Accretion expense |
| 11.5 |
| 11.1 |
| ||||
Balance, end of year |
| $ | 140.0 |
| $ | 177.3 |
| ||
11. Financial Instruments
The Trust is exposed to a number of financial risks that are part of its normal course of business. The Trust has a risk management program in place that includes financial instruments as disclosed in this note. ARC’s risk management program is overseen by an experienced risk management committee based on guidelines approved by the board of directors. The objective of the risk management program is to mitigate the Trust’s exposure to the following financial risks:
COMMODITY PRICE RISKS
The Trust’s operational results and financial condition, and therefore the amount of distributions paid to unitholders, are dependent on the commodity prices received for oil and natural gas production and the price paid for electricity. Commodity prices have fluctuated widely during recent years and are determined by weather, economic and, in the case of oil prices, geopolitical factors. Any movement in commodity prices could have an effect on the Trust’s financial condition and therefore on the distributions to unitholders. ARC manages the risks associated with changes in commodity prices by entering into risk management contracts.
VARIATIONS IN INTEREST RATES
The Trust has both fixed and variable interest debt. Changes in interest rates could result in a significant increase or decrease in the amount the Trust pays to service variable interest debt, potentially impacting distributions to unitholders. Changes in interest rates could also result in fair value risk on the Trust’s senior secured notes. This risk is mitigated due to the fact that the Trust does not intend to settle its fixed rate debt prior to maturity. ARC manages the risk associated with changes in interest rates by entering into financial swaps in order to lock in favorable fixed or floating rates.
VARIATIONS IN FOREIGN EXCHANGE RATES
World commodity prices are quoted in U.S. dollars, therefore the price received by Canadian producers is affected by the Canadian/U.S. dollar exchange rate that may fluctuate over time. Variations in the exchange rate of the Canadian dollar could have significant positive or negative impact on distributions to unitholders. ARC has initiated certain risk management contracts to mitigate these risks.
CREDIT RISK
The Trust is exposed to credit risk with respect to its accounts receivable and risk management contracts. Most of the Trust’s accounts receivable relate to oil and natural gas sales and are exposed to typical industry credit risks. The Trust manages this credit risk by entering into sales contracts with only established entities and reviewing its exposure to individual entities on a regular basis. The Trust minimizes credit risk on risk management contracts by entering into agreements with counterparties that are of investment grade.
18
The Trust has a legal right to offset asset and liability positions with some of its counterparties. In situations where there is a legal right to offset, balances are still shown gross on the Consolidated Balance Sheet as it is not the Trust’s intention to net settle. Only in situations of credit default would these asset and liability positions be shown net on the Consolidated Balance Sheet.
Maximum credit risk is calculated as the total positive value of accounts receivable and risk management contracts at the balance sheet date less any liability amounts where there is a legal right to offset, to the extent that there are positive value accounts receivable or risk management contracts with the same counterparty. The following table details the Trust’s maximum credit risk as at December 31:
|
| 2007 |
| 2006 |
| ||||
Trade accounts receivable |
| $ | 159.5 |
| $ | 129.8 |
| ||
Risk management contracts |
| 6.8 |
| 21.9 |
| ||||
Maximum credit exposure |
| $ | 166.3 |
| $ | 151.7 |
| ||
While the Trust is exposed to the above credit losses due to the potential non-performance of its counterparties, the Trust considers the risk of this remote.
FINANCIAL INSTRUMENTS
Financial Instruments of the Trust carried on the Consolidated Balance Sheet are carried at cost with the exception of reclamation fund assets classified as-available-for-sale and risk management contracts, which are carried at fair value. Except for those items noted in the table below there were no significant differences between the carrying value of financial instruments and their estimated fair values, at December 31:
|
| Carrying Value |
| Fair Value |
| ||||||||
|
| 2007 |
| 2006 |
| 2007 |
| 2006 |
| ||||
Reclamation fund assets classified as available-for-sale (1) |
| $ | 8.1 |
| $ | 5.2 |
| $ | 8.1 |
| $ | 5.2 |
|
Reclamation fund assets classified as held-to-maturity (1) |
| 18.0 |
| 25.7 |
| 17.8 |
| 27.7 |
| ||||
Senior secured notes (2) |
| 215.5 |
| 261.0 |
| 226.1 |
| 257.0 |
| ||||
(1) Fair value obtained from third parties, determined directly by reference to quoted market prices.
(2) Fair value calculated as the present value of future principal and interest payments discounted at the Trust’s credit adjusted risk free rate.
RISK MANAGEMENT CONTRACTS
The Trust uses a variety of derivative instruments to reduce its exposure to fluctuations in commodity prices, foreign exchange, interest rates and power. The Trust considers all of these transactions to be effective economic hedges, however, the majority of the Trust’s contracts do not qualify as effective hedges for accounting purposes.
Following is a summary of all risk management contracts in place as at December 31, 2007 that do not qualify for hedge accounting:
19
FINANCIAL WTI CRUDE OIL CONTRACTS
|
|
|
| Volume |
| Bought Put |
| Sold Put |
| Sold Call |
| Bought Call |
|
Term |
| Contract |
| bbl/d |
| US$/bbl |
| US$/bbl |
| US$/bbl |
| US$/bbl |
|
Jan 08 – Mar 08 |
| Collar |
| 2,000 |
| 92.50 |
| — |
| 110.00 |
| — |
|
Jan 08 – Mar 08 |
| Collar |
| 2,000 |
| 92.50 |
| — |
| 105.00 |
| — |
|
Jan 08 – Mar 08 |
| Covered Collar |
| 2,000 |
| 90.00 |
| — |
| 105.00 |
| 120.00 |
|
Jan 08 – Mar 08 |
| Bought Put |
| 500 |
| 84.00 |
| — |
| — |
| — |
|
Jan 08 – Mar 08 |
| 3 - Way Collar |
| 1,000 |
| 84.00 |
| 69.00 |
| 105.00 |
| — |
|
Jan 08 – Mar 08 |
| Put Spread |
| 500 |
| 83.00 |
| 68.00 |
| — |
| — |
|
Jan 08 – Mar 08 |
| 3 - Way Collar |
| 1,000 |
| 79.00 |
| 66.00 |
| 105.00 |
| — |
|
Jan 08 – Jun 08 |
| 3 - Way Collar |
| 1,000 |
| 65.00 |
| 52.50 |
| 82.50 |
| — |
|
Jan 08 – Jun 08 |
| 3 - Way Collar |
| 1,000 |
| 65.00 |
| 52.50 |
| 85.00 |
| — |
|
Jan 08 – Jun 08 |
| Collar |
| 1,000 |
| 65.00 |
| — |
| 85.00 |
| — |
|
Jan 08 – Dec 08 |
| 3 - Way Collar |
| 1,000 |
| 70.00 |
| 55.00 |
| 90.00 |
| — |
|
Jan 08 – Dec 08 |
| 3 - Way Collar |
| 1,000 |
| 67.50 |
| 52.50 |
| 85.00 |
| — |
|
Jan 08 – Dec 08 |
| Collar |
| 1,000 |
| 67.50 |
| — |
| 85.00 |
| — |
|
Jan 08 – Dec 08 |
| 3 - Way Collar |
| 2,000 |
| 61.50 |
| 50.00 |
| 85.00 |
| — |
|
Jan 08 – Dec 08 |
| 3 - Way Collar |
| 1,000 |
| 61.30 |
| 50.00 |
| 85.00 |
| — |
|
Jan 08 – Dec 08 |
| 3 - Way Collar |
| 2,000 |
| 61.00 |
| 50.00 |
| 85.00 |
| — |
|
Apr 08 – Jun 08 |
| Collar |
| 2,000 |
| 90.00 |
| — |
| 110.00 |
| — |
|
Apr 08 – Jun 08 |
| Put Spread |
| 500 |
| 85.00 |
| 70.00 |
| — |
| — |
|
Apr 08 – Jun 08 |
| Put Spread |
| 500 |
| 85.00 |
| 69.00 |
| — |
| — |
|
Apr 08 – Jun 08 |
| Put Spread |
| 500 |
| 84.00 |
| 68.00 |
| — |
| — |
|
Apr 08 – Jun 08 |
| Put Spread |
| 1,000 |
| 79.00 |
| 66.00 |
| — |
| — |
|
Jul 08 – Dec 08 |
| Collar |
| 2,000 |
| 85.00 |
| — |
| 107.50 |
| — |
|
Jan 09 – Dec 09 |
| 3 - Way Collar |
| 5,000 |
| 55.00 |
| 40.00 |
| 90.00 |
| — |
|
FINANCIAL AECO NATURAL GAS OPTION CONTRACTS
|
|
|
| Volume |
| Bought Put |
| Sold Put |
| Sold Call |
|
Term |
| Contract |
| GJ/d |
| CDN$/GJ |
| CDN$/GJ |
| CDN$/GJ |
|
Apr 08 – Oct 08 |
| Collar |
| 10,000 |
| 7.00 |
| — |
| 9.00 |
|
Apr 08 – Oct 08 |
| 3 - Way Collar |
| 10,000 |
| 7.00 |
| 5.75 |
| 9.00 |
|
FINANCIAL NYMEX NATURAL GAS CONTRACTS
|
|
|
| Volume |
| Bought Put |
| Sold Put |
| Sold Call |
|
Term |
| Contract |
| mmbtu/d |
| US$/mmbtu |
| US$/mmbtu |
| US$/mmbtu |
|
Jan 08 – Mar 08 |
| 3 - Way Collar |
| 10,000 |
| 9.25 |
| 6.25 |
| 10.00 |
|
Jan 08 – Mar 08 |
| Collar |
| 20,000 |
| 8.50 |
| — |
| 10.00 |
|
Jan 08 – Mar 08 |
| Collar |
| 5,000 |
| 7.85 |
| — |
| 9.40 |
|
Jan 08 – Mar 08 |
| Collar |
| 5,000 |
| 8.25 |
| — |
| 9.25 |
|
Jan 08 – Mar 08 |
| Collar |
| 5,000 |
| 8.00 |
| — |
| 9.00 |
|
Apr 08 – Oct 08 |
| 3 - Way Collar |
| 10,000 |
| 8.00 |
| 6.00 |
| 9.60 |
|
Apr 08 – Oct 08 |
| 3 - Way Collar |
| 10,000 |
| 7.80 |
| 6.20 |
| 9.50 |
|
Nov 08 – Mar 09 |
| Collar |
| 20,000 |
| 8.50 |
| — |
| 11.00 |
|
20
FINANCIAL BASIS SWAP CONTRACT: RECEIVE NYMEX (LAST 3 DAY); PAY AECO (MONTHLY)
|
|
|
| Volume |
| Basis Swap |
|
Term |
| Contract |
| mmbtu/d |
| US$ /mmbtu |
|
Jan 08 – Oct 08 |
| Basis Swap |
| 50,000 |
| (1.1930 | ) |
Nov 08 – Oct 10 |
| Basis Swap |
| 50,000 |
| (1.0430 | ) |
ENERGY EQUIVALENT SWAP
Term |
| Contract |
| Volume |
| Swap |
|
Financial WTI Crude Oil Purchase Contract |
|
|
|
|
|
|
|
Apr 08 – Oct 08 |
| Swap |
| 1,000 bbl/d |
| 73.95 CDN$/bbl |
|
|
|
|
|
|
|
|
|
Financial AECO Natural Gas Sales Contract |
|
|
|
|
|
|
|
Apr 08 – Oct 08 |
| Swap |
| 10,000 GJ/d |
| 7.10 CDN$/GJ |
|
FINANCIAL FOREIGN EXCHANGE CONTRACTS
|
|
|
| National |
|
|
|
|
|
|
|
|
|
|
|
|
| Volume |
| Swap |
| Swap |
| Bought Put |
| Sold Put |
|
Term |
| Contract |
| MM US$ |
| CDN$/US$ |
| US$/CDN$ |
| CDN$/US$ |
| CDN$/US$ |
|
USD Option Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
Jan 08 – Dec 08 |
| Put Spread |
| 12.0 |
| — |
| — |
| 1.0750 |
| 1.0300 |
|
USD LONG-TERM PRINCIPAL DEBT REPAYMENT CONTRACTS
|
|
|
| Notional |
|
|
|
|
|
|
|
|
|
|
|
|
| Volume |
| Swap |
| Swap |
| Bought Call |
| Sold Put |
|
Settlement Date |
| Contract |
| MM US$ |
| CDN$/US$ |
| US$/CDN$ |
| CDN$/US$ |
| CDN$/US$ |
|
December 17, 2012 |
| Forward |
| 9.38 |
| 0.9324 |
| (1.0725 | ) | — |
| — |
|
April 27, 2013 |
| Forward |
| 10.42 |
| 0.9454 |
| (1.0578 | ) | — |
| — |
|
April 27, 2013 |
| Forward |
| 12.50 |
| 0.9430 |
| (1.0604 | ) | — |
| — |
|
December 15, 2013 |
| Forward |
| 9.38 |
| 0.9520 |
| (1.0504 | ) | — |
| — |
|
April 27, 2014 |
| Forward |
| 10.42 |
| 0.9743 |
| (1.0264 | ) | — |
| — |
|
April 27, 2014 |
| Forward |
| 12.50 |
| 0.9615 |
| (1.0400 | ) | — |
| — |
|
December 15, 2014 |
| Forward |
| 9.38 |
| 0.9825 |
| (1.0178 | ) | — |
| — |
|
April 27, 2015 |
| Forward |
| 12.50 |
| 0.9825 |
| (1.0178 | ) | — |
| — |
|
December 15, 2015 |
| Forward |
| 9.40 |
| 0.9980 |
| (1.0020 | ) | — |
| — |
|
April 27, 2016 |
| Forward |
| 12.50 |
| 1.0180 |
| (0.9823 | ) | — |
| — |
|
December 15, 2017 |
| Forward |
| 9.40 |
| 1.0184 |
| (0.9819 | ) | — |
| — |
|
December 15, 2016 |
| Collar |
| 9.40 |
| — |
| — |
| 1.0600 |
| 1.0000 |
|
FINANCIAL INTEREST RATE CONTRACTS (1)(2)
|
|
|
| Principal |
| Fixed Annual |
| Spread on |
|
Term |
| Contract |
| MM US$ |
| Rate (%) |
| 3 Mo. LIBOR |
|
Jan 08 – Apr 14 |
| Swap |
| 30.5 |
| 4.62 |
| 38 bps |
|
Jan 08 – Apr 14 |
| Swap |
| 32.0 |
| 4.62 |
| (25.5 bps | ) |
(1) Starting in 2009, the notional amount of the contracts decreases annually until 2014. The Trust pays the floating interest rate based on a three month LIBOR plus a spread and receives the fixed interest rate.
(2) Starting in 2009 a mutual put exists where both parties have the right to call on the other party to pay the then current mark-to-market value of the contract.
21
Following is a summary of all risk management contracts in place as at December 31, 2007 that qualify for hedge accounting:
FINANCIAL ELECTRICITY CONTRACTS (3)(4)
|
|
|
| Volume |
| Swap |
|
Term |
| Contract |
| MWh |
| CDN$/MWh |
|
Jan 08 – Dec 08 |
| Swap |
| 15.0 |
| 60.17 |
|
Jan 09 – Dec 09 |
| Swap |
| 15.0 |
| 59.33 |
|
Jan 10 – Dec 10 |
| Swap |
| 5.0 |
| 63.00 |
|
(3) Contracted volume is based on a 24/7 term.
(4) Includes margin provision on 5 MWh per year if contract value exceeds $30M. If exercised a letter of credit would be issued for values in excess of $30 million.
USD NOTE TREASURY RATE LOCKS
|
| Principal |
| Interest |
|
Settlement Date |
| MM US$ |
| Rate (%) |
|
February 15, 2008 |
| 125.0 |
| 4.8082 | (5) |
(5) Rate is based on 10 year US Treasury Bond.
During the year the Trust entered into treasury rate lock contracts in order to manage the Trust’s interest rate exposure on future debt issuances. These contracts have been designated as effective accounting hedges on their respective contract dates and hedge accounting has been applied. The unrealized fair value loss on these contracts of $7.4 million has been recorded on the Consolidated Balance Sheet at December 31, 2007 with the movement in the fair value recorded in OCI, net of tax. Ineffectiveness as at December 31, 2007 is nominal and was calculated by considering the present value of future cash flows on the original treasury rate lock contract and the rate effective on the contract at December 31, 2007. The maximum expected term for which the Trust is hedging its interest rate risk exposure is 10 years, which is the expected term of the future debt issuance. It is expected that a $0.8 million fair value loss will be reclassified to Net Income within the next 12 months.
The Trust’s fixed price electricity contracts are intended to manage price risk on electricity consumption. All fixed price electricity contracts were designated as effective accounting hedges on their respective contract dates. A realized gain of $0.4 million on the electricity contracts has been included in operating costs ($3.4 million gain in 2006). The unrealized fair value gain on the electricity contracts of $4 million has been recorded on the Consolidated Balance Sheet at December 31, 2007 with the movement in fair value recorded in OCI, net of tax. The fair value movement as at December 31, 2007 amounts to an unrealized loss of $3 million. $1.9 million of this gain is expected to be recognized in income over the next 12 months.
The Trust has entered into interest rate swap contracts to manage the Company’s interest rate exposure on debt instruments. Prior to 2007, these contracts were designated as effective accounting hedges on the contract date. At January 1, 2007 the Trust elected to cease applying hedge accounting to these contracts.
The following table reconciles the movement in the fair value of the Trust’s financial risk management contracts that have not been designated as effective accounting hedges:
|
| December 31, 2007 |
| December 31, 2006 |
| ||
Fair value, beginning of year (1) |
| $ | (8.7 | ) | $ | (4.1 | ) |
Fair value, end of year (1) (2) |
| (64.6 | ) | (8.7 | ) | ||
Change in fair value of contracts in the year |
| (55.9 | ) | (4.6 | ) | ||
Realized gains in the year |
| 14.1 |
| 29.3 |
| ||
(Loss) gain on risk management contracts (1) |
| $ | (41.8 | ) | $ | 24.7 |
|
(1) For 2007 the fixed price electricity and treasury rate lock contracts that were accounted for as effective accounting hedges were excluded. For 2006 the fixed price electricity contract and interest rate swap contracts that were accounted for as effective accounting hedges were excluded.
(2) Intrinsic value of risk management contracts not designated as effective accounting hedges equals a loss of $47.6 million at December 31, 2007 ($5.3 million loss in 2006).
22
The following table reconciles the movement in the fair value of the Trust’s financial electricity and treasury rate lock contracts that have been designated as effective accounting hedges:
|
| December 31, 2007 |
| December 31, 2006 |
| ||
Fair value, beginning of year |
| $ | 7.0 |
| $ | (0.2 | ) |
Fair value, end of year |
| (3.4 | ) | 7.0 |
| ||
Change in fair value of contracts in the year (3) |
| $ | (10.4 | ) | $ | 7.2 |
|
(3) In 2006 fair value amounts relating to risk management contracts that qualified for hedge accounting were not recorded on the Consolidated Balance Sheet.
At December 31, 2007, the fair value of the contracts that were not designated as accounting hedges was a loss of $64.6 million. The Trust recorded a loss on risk management contracts of $41.8 million in the Statement of Income for the year ended 2007 ($24.7 million gain in 2006). This amount includes the realized and unrealized gains and losses on risk management contracts that do not qualify as effective accounting hedges.
The fair values of all risk management contracts are determined using published price quotations in an active market through a valuation model. Significant inputs into this model include forward curves on commodity prices, interest rates and foreign exchange rates.
12. Gain (Loss) On Foreign Exchange
The following is a summary of the total gain (loss) on US$ denominated transactions:
|
| 2007 |
| 2006 |
| ||
Unrealized gain (loss) on US$ denominated debt |
| $ | 64.6 |
| $ | (7.1 | ) |
Realized gain on US$ denominated debt repayments |
| 5.0 |
| 2.6 |
| ||
Total non-cash gain (loss) on US$ denominated transactions |
| 69.6 |
| (4.5 | ) | ||
Realized cash (loss) gain on US$ denominated transactions |
| (0.2 | ) | 0.3 |
| ||
Total foreign exchange gain (loss) |
| $ | 69.4 |
| $ | (4.2 | ) |
13. Income Taxes
In 2007, Income Trust tax legislation was passed resulting in a two-tiered tax structure subjecting distributions to the federal corporate income tax rate plus a deemed 13 per cent provincial income tax at the Trust level commencing in 2011. Currently, distributions paid to unitholders, other than returns of capital, are claimed as a deduction by the Trust in arriving at taxable income whereby tax is eliminated at the Trust level and is paid by the unitholders. As a result, the future tax position of the Trust, the parent entity, is now required to be reflected in the consolidated future income tax calculation. The Trust recorded a $24.7 million one time increase in earnings and a corresponding decrease to its future income tax liability as a result of timing differences within the Trust that had not been previously recognized.
On October 30, 2007, the Finance Minister announced a reduction of the corporate income tax rate from 22.1 per cent to 15 percent by 2012. The reductions will be phased in between 2008 and 2012. Legislation enacting the measures received Royal Assent on December 14, 2007. The reduction in the general corporate tax rate will also apply to the taxation of Income Trusts, reducing the combined federal and deemed Provincial tax rate for distributions to 28 per cent in 2012.
23
The tax provision differs from the amount computed by applying the combined Canadian federal and provincial statutory income tax rates to income before future income tax recovery as follows:
|
| 2007 |
| 2006 |
| ||
Income before future income tax recovery |
| $ | 380.8 |
| $ | 379.6 |
|
Canadian statutory rate (1) |
| 34.3 | % | 34.5 | % | ||
Expected income tax expense at statutory rates |
| 130.6 |
| 130.9 |
| ||
Effect on income tax of: |
|
|
|
|
| ||
Net income of the Trust |
| (163.6 | ) | (138.0 | ) | ||
Effect of change in corporate tax rate |
| (41.3 | ) | (62.2 | ) | ||
Initial recognition of Trust tax pools |
| (24.7 | ) | — |
| ||
Unrealized (gain) loss on foreign exchange |
| (10.4 | ) | 1.2 |
| ||
Change in estimated pool balances |
| (7.0 | ) | (10.0 | ) | ||
Non-taxable portion of gains/losses |
| (2.1 | ) | — |
| ||
Resource allowance |
| — |
| (10.7 | ) | ||
Non-deductible crown charges |
| — |
| 1.2 |
| ||
Other non-deductible items |
| (2.8 | ) | 0.5 |
| ||
Future income tax recovery |
| $ | (121.3 | ) | $ | (87.1 | ) |
(1) The statutory rate consists of the combined Trust and Trust’s subsidiaries statutory tax rate
The net future income tax liability comprises the following:
|
| 2007 |
| 2006 |
| ||
Future tax liabilities: |
|
|
|
|
| ||
Capital assets in excess of tax value |
| $ | 371.6 |
| $ | 509.8 |
|
Long-term debt |
| 11.9 |
| 4.0 |
| ||
Future tax assets: |
|
|
|
|
| ||
Asset retirement obligations |
| (36.1 | ) | (52.1 | ) | ||
Risk management contracts |
| (16.7 | ) | (2.5 | ) | ||
Accrued long-term incentive compensation |
| (7.8 | ) | (7.7 | ) | ||
Non-capital losses |
| (3.8 | ) | (5.3 | ) | ||
Attributed Canadian royalty income |
| (4.6 | ) | (10.4 | ) | ||
Cumulative eligible capital and deductible share issue costs |
| (1.6 | ) | (1.6 | ) | ||
Other comprehensive loss |
| (0.7 | ) | — |
| ||
Net future income tax liability |
| $ | 312.2 |
| $ | 434.2 |
|
Current portion of net future income tax liability |
| $ | (4.0 | ) | $ | — |
|
Long-term portion of net future income tax liability |
| $ | 316.2 |
| $ | 434.2 |
|
The petroleum and natural gas properties and facilities owned by the Trust have an approximate tax basis of $1.84 billion ($1.58 billion in 2006) available for future use as deductions from taxable income. Included in this tax basis are estimated non-capital loss carry forwards of $13.8 million ($18.2 million in 2006) that expire in the years 2010 through 2026. The following is a summary of the estimated Trust’s tax pools:
The 2006 comparative tax pools have been restated to include the tax pools of the Trust and of the Trust’s subsidiaries. The 2006 tax pools disclosed in the prior year for the Trust’s subsidiaries were $1.03 billion. In addition, the Trust itself had an approximate tax basis of $545.1 million as at December 31, 2006.
24
|
| 2007 |
| 2006 |
| |||
Canadian oil and gas property expenses |
| $ | 816.5 |
| $ | 734.0 |
| |
Canadian development expenses |
| 326.1 |
| 285.9 |
| |||
Canadian exploration expenses |
| 52.5 |
| 27.7 |
| |||
Undepreciated capital cost |
| 460.2 |
| 389.0 |
| |||
Non-capital losses |
| 13.8 |
| 18.2 |
| |||
Provincial tax pools |
| 161.1 |
| 104.5 |
| |||
Other |
| 10.3 |
| 16.8 |
| |||
Estimated tax basis |
| $ | 1,840.5 |
| $ | 1,576.1 |
| |
No current income taxes were paid or payable in both 2007 and 2006.
14. Exchangeable Shares
The ARC Resources exchangeable shares (“ARL Exchangeable Shares”) were issued on January 31, 2001 at $11.36 per exchangeable share as partial consideration for the Startech Energy Inc. acquisition. The issue price of the exchangeable shares was determined based on the weighted average trading price of Trust units preceding the date of announcement of the acquisition. The ARL Exchangeable Shares had an exchange ratio of 1:1 at the time of issuance.
The Trust is authorized to issue an unlimited number of ARL Exchangeable Shares which can be converted (at the option of the holder) into Trust units at any time. The number of Trust units issuable upon conversion is based upon the exchange ratio in effect at the conversion date. The exchange ratio is calculated monthly based on the cash distribution paid divided by the ten day weighted average unit price preceding the record date and multiplied by the opening exchange ratio. The exchangeable shares are not eligible for distributions and, in the event that they are not exchanged, any outstanding shares are redeemable by the Trust for Trust units on August 28, 2012. The ARL Exchangeable Shares are publicly traded.
ARL Exchangeable Shares (thousands):
|
| 2007 |
| 2006 |
|
Balance, beginning of year |
| 1,433 |
| 1,595 |
|
Exchanged for Trust units |
| (123 | ) | (162 | ) |
Balance, end of year |
| 1,310 |
| 1,433 |
|
Exchange ratio, end of year |
| 2.24976 |
| 2.01251 |
|
Trust units issuable upon conversion, end of year |
| 2,947 |
| 2,884 |
|
The non-controlling interest on the Consolidated Balance Sheet consists of the fair value of the exchangeable shares upon issuance plus the accumulated earnings attributable to the non-controlling interest. The net income attributable to the non-controlling interest on the Consolidated Statement of Income represents the cumulative share of net income attributable to the non-controlling interest based on the Trust units issuable for exchangeable shares in proportion to total Trust units issued and issuable at each period end.
Following is a summary of the non-controlling interest for 2007 and 2006:
|
| 2007 |
| 2006 |
| ||
Non-controlling interest, beginning of year |
| $ | 40.0 |
| $ | 37.5 |
|
Reduction of book value for conversion to Trust units |
| (3.7 | ) | (4.1 | ) | ||
Current year net income attributable to non-controlling interest |
| 6.8 |
| 6.6 |
| ||
Non-controlling interest, end of year |
| $ | 43.1 |
| $ | 40.0 |
|
Accumulated earnings attributable to non-controlling interest |
| $ | 34.1 |
| $ | 27.3 |
|
25
15. Unitholders’ Capital
The Trust is authorized to issue 650 million Trust units of which 210.2 million units were issued and outstanding as at December 31, 2007 (204.3 million as at December 31, 2006).
The Trust has in place a Distribution Reinvestment and Optional Cash Payment Program (“DRIP”) in conjunction with the Trust’s transfer agent to provide the option for unitholders to reinvest cash distributions into additional Trust units issued from treasury at a five per cent discount to the prevailing market price with no additional fees or commissions.
The Trust is an open ended mutual fund under which unitholders have the right to request redemption directly from the Trust. Trust
units tendered by holders are subject to redemption under certain terms and conditions including the determination of the redemption price at the lower of the closing market price on the date units are tendered or 90 per cent of the weighted average trading price for the 10 day trading period commencing on the tender date. Cash payments for units tendered for redemption are limited to $100,000 per month with redemption requests in excess of this amount eligible to receive a note from ARC Resources Ltd. accruing interest at 4.5 per cent and repayable within 20 years.
|
| 2007 |
| 2006 |
| ||||
|
| Number of |
|
|
| Number of |
|
|
|
|
| Trust Units |
| $ |
| Trust Units |
| $ |
|
|
| (thousands) |
|
|
| (thousands) |
|
|
|
Balance, beginning of year |
| 204,289 |
| 2,349.2 |
| 199,104 |
| 2,230.8 |
|
Issued for cash |
| — |
| — |
| 1 |
| — |
|
Issued on conversion of ARL exchangeable shares (Note 14) |
| 261 |
| 3.7 |
| 310 |
| 4.1 |
|
Issued on exercise of employee rights (Note 18) |
| 131 |
| 2.1 |
| 978 |
| 18.4 |
|
Distribution reinvestment program |
| 5,551 |
| 110.7 |
| 3,896 |
| 96.1 |
|
Trust unit issue costs |
| — |
| — |
| — |
| (0.2 | ) |
Balance, end of year |
| 210,232 |
| 2,465.7 |
| 204,289 |
| 2,349.2 |
|
16. Deficit and Accumulated Other Comprehensive Loss
The deficit balance is composed of the following items:
|
| 2007 |
| 2006 |
| ||
Accumulated earnings |
| $ | 2,191.1 |
| $ | 1,695.8 |
|
Accumulated distributions |
| (2,657.0 | ) | (2,159.0 | ) | ||
Deficit |
| $ | (465.9 | ) | $ | (463.2 | ) |
Accumulated other comprehensive loss |
| (2.9 | ) | — |
| ||
Deficit and accumulated other comprehensive loss |
| $ | (468.8 | ) | $ | (463.2 | ) |
The accumulated other comprehensive loss balance is composed of the following items:
|
| 2007 |
| 2006 |
| ||
Unrealized losses on financial instruments designated as cash flow hedges |
| $ | (2.8 | ) | $ | — |
|
Net unrealized loss on available-for-sale reclamation funds’ investments |
| (0.1 | ) | — |
| ||
Accumulated other comprehensive loss, end of year |
| $ | (2.9 | ) | $ | — |
|
26
17. Reconciliation of Cash Flow from Operating Activities and Distributions
Distributions are calculated in accordance with the Trust Indenture. To arrive at distributions, cash flow from operating activities is reduced by reclamation fund contributions including interest earned on the funds, a portion of capital expenditures and, when applicable, debt repayments. The portion of cash flow from operating activities withheld to fund capital expenditures and to make debt repayments is at the discretion of the Board of Directors.
|
| 2007 |
| 2006 |
| ||
Cash flow from operating activities |
| $ | 704.9 |
| $ | 734.0 |
|
Deduct: |
|
|
|
|
| ||
Cash withheld to fund current year capital expenditures |
| (193.4 | ) | (236.7 | ) | ||
Reclamation fund contributions and interest earned on fund balances |
| (13.5 | ) | (13.1 | ) | ||
Distributions (1) |
| 498.0 |
| 484.2 |
| ||
Accumulated distributions, beginning of year |
| 2,159.0 |
| 1,674.8 |
| ||
Accumulated distributions, end of year |
| $ | 2,657.0 |
| $ | 2,159.0 |
|
Distributions per unit (2) |
| $ | 2.40 |
| $ | 2.40 |
|
Accumulated distributions per unit, beginning of year (3) |
| $ | 18.63 |
| $ | 16.23 |
|
Accumulated distributions per unit, end of year (3) |
| $ | 21.03 |
| $ | 18.63 |
|
(1) Distributions include non-cash amounts of $110 million ($94 million in 2006) relating to the distribution reinvestment program.
(2) Distributions and per trust unit reflect the sum of the per trust unit amounts declared monthly to unitholders.
(3) Accumulated distributions per trust unit reflect the sum of the per trust unit amounts declared monthly to unitholders since the inception of the Trust in July 1996.
18. Trust Unit Incentive Rights Plan
The Trust Unit Incentive Rights Plan (the “Rights Plan”) was established in 1999 and authorized the Trust to grant up to 8,000,000 rights to its employees, independent directors and long-term consultants to purchase Trust units, of which 7,866,088 were granted to December 31, 2007. The initial exercise price of rights granted under the Rights Plan could not be less than the market price of the Trust units as at the date of grant and the maximum term of each right was not to exceed ten years. In general, the rights have a five year term and vest equally over three years commencing on the first anniversary date of the grant. In addition, the exercise price of the rights is to be adjusted downwards from time to time by the amount, if any, that distributions to unitholders in any calendar quarter exceeds 2.5 per cent (ten per cent annually) of the Trust’s net book value of property, plant and equipment (the “Excess Distribution”), as determined by the Trust.
During 2007, 2006 and 2005, the Trust did not grant any rights as the Rights Plan was replaced with a Whole Unit Plan during 2004 (see Note 19). The existing Rights Plan will be in place until the remaining 0.2 million rights outstanding as at December 31, 2007 are exercised or cancelled.
A summary of the changes in rights outstanding under the Rights Plan is as follows:
|
| 2007 |
| 2006 |
| ||||
|
|
|
| Weighted |
|
|
| Weighted |
|
|
| Number |
| Average |
| Number |
| Average |
|
|
| of Rights |
| Exercise |
| of Rights |
| Exercise |
|
|
| (thousands) |
| Price ($) |
| (thousands) |
| Price ($) |
|
Balance, beginning of year |
| 369 |
| 9.47 |
| 1,349 |
| 10.22 |
|
Exercised |
| (131 | ) | 10.77 |
| (978 | ) | 12.19 |
|
Cancelled |
| — |
| — |
| (2 | ) | 10.07 |
|
Balance before reduction of exercise price |
| 238 |
| 9.41 |
| 369 |
| 10.40 |
|
Reduction of exercise price (1) |
| — |
| (0.91 | ) | — |
| (0.93 | ) |
Balance, end of year |
| 238 |
| 8.50 |
| 369 |
| 9.47 |
|
(1) The holder of the right has the option to exercise rights held at the original grant price or a reduced exercise price.
27
All rights outstanding are exercisable and have a remaining contractual life of 0.4 years.
The Trust recorded a nominal amount of compensation expense for the year ($2.5 million in 2006) for the cost associated with the rights. Of the 3,013,569 rights issued on or after January 1, 2003 that were subject to recording compensation expense, 357,999 rights have been cancelled and 2,419,239 rights have been exercised to December 31, 2007.
The following table reconciles the movement in the contributed surplus balance for 2007 and 2006:
|
| 2007 |
| 2006 |
| ||
Balance, beginning of year |
| $ | 2.4 |
| $ | 6.4 |
|
Compensation expense |
| — |
| 2.5 |
| ||
Net benefit on rights exercised (1) |
| (0.7 | ) | (6.5 | ) | ||
Balance, end of year |
| $ | 1.7 |
| $ | 2.4 |
|
(1) Upon exercise, the net benefit is reflected as a reduction of contributed surplus and an increase to unitholders’ capital.
19. Whole Trust Unit Incentive Plan
In March 2004, the Board of Directors, upon recommendation of the Compensation Committee, approved a new Whole Trust Unit Incentive Plan (the “Whole Unit Plan”) to replace the existing Trust Unit Incentive Rights Plan for new awards granted subsequent to March 31, 2004. The new Whole Unit Plan will result in employees, officers and directors (the “plan participants”) receiving cash compensation in relation to the value of a specified number of underlying notional trust units. The Whole Unit Plan consists of Restricted Trust Units (“RTUs”) for which the number of trust units is fixed and will vest over a period of three years and Performance Trust Units (“PTUs”) for which the number of trust units is variable and will vest at the end of three years.
Upon vesting, the plan participant receives a cash payment based on the fair value of the underlying trust units plus notional
accrued distributions. The cash compensation issued upon vesting of the PTUs is dependent upon the future performance of the Trust compared to its peers based on a performance multiplier. The performance multiplier is based on the percentile rank of the Trust’s Total Unitholder Return. The cash compensation issued upon vesting of the PTUs may range from zero to two times the value of the PTUs originally granted.
The fair value associated with the RTUs and PTUs is expensed in the statement of income over the vesting period. As the value of the RTUs and PTUs is dependent upon the trust unit price, the expense recorded in the statement of income may fluctuate over time.
The Trust recorded non-cash compensation expense of $3.2 million and $0.3 million to general and administrative and operating expenses, respectively, and capitalized $0.7 million to property, plant and equipment in the twelve months ended December 31, 2007 for the estimated cost of the plan ($8.2 million, $1.1 million, and $1.8 million for the twelve months ended December 31, 2006). The non-cash compensation expense was based on the December 31, 2007 unit price of $20.40 ($22.30 in 2006), accrued distributions, a weighted average performance multiplier of 1.7 (2.0 in 2006), and the number of units to be issued on maturity.
The following table summarizes the RTU and PTU movement for the twelve months ended December 31, 2007 and 2006:
|
| 2007 |
| 2006 |
| ||||
|
| Number of |
| Number of |
| Number of |
| Number of |
|
|
| (thousands) |
| (thousands) |
| (thousands) |
| (thousands) |
|
Balance, beginning of year |
| 648 |
| 683 |
| 479 |
| 391 |
|
Vested |
| (286 | ) | (110 | ) | (180 | ) | — |
|
Granted |
| 422 |
| 362 |
| 373 |
| 303 |
|
Forfeited |
| (38 | ) | (32 | ) | (24 | ) | (11 | ) |
Balance, end of year |
| 746 |
| 903 |
| 648 |
| 683 |
|
28
The following table reconciles the change in total accrued compensation liability relating to the Whole Unit Plan:
|
| 2007 |
| 2006 |
| ||
Balance, beginning of year |
| $ | 26.1 |
| $ | 15.0 |
|
Change in liabilities in the year |
|
|
|
|
| ||
General and administrative expense |
| 3.2 |
| 8.2 |
| ||
Operating expense |
| 0.3 |
| 1.1 |
| ||
Property, plant and equipment |
| 0.7 |
| 1.8 |
| ||
Balance, end of year |
| $ | 30.3 |
| $ | 26.1 |
|
Current portion of liability (Note 8) |
| 18.2 |
| 11.5 |
| ||
Long-term liability |
| $ | 12.1 |
| $ | 14.6 |
|
During the year $12.7 million in cash payments were made to employees relating to the Whole Unit Plan ($5.2 million in 2006).
20. Basic and Diluted Per Trust Unit Calculations
Net income per trust unit has been determined based on the following:
|
| 2007 |
| 2006 |
|
|
| (thousands) |
| (thousands) |
|
Weighted average trust units (1) |
| 207,287 |
| 201,554 |
|
Trust units issuable on conversion of exchangeable shares (2) |
| 2,947 |
| 2,884 |
|
Dilutive impact of rights (3) |
| 174 |
| 711 |
|
Dilutive trust units and exchangeable shares |
| 210,408 |
| 205,149 |
|
(1) Weighted average trust units exclude trust units issuable for exchangeable shares.
(2) Diluted trust units include trust units issuable for outstanding exchangeable shares at the period end exchange ratio.
(3) All outstanding rights were dilutive and therefore have been included in the diluted unit calculation for both 2007 and 2006.
Basic net income per unit has been calculated based on net income after non-controlling interest divided by weighted average
trust units. Diluted net income per unit has been calculated based on net income before non-controlling interest divided by dilutive
trust units.
21. Commitments and Contingencies
Following is a summary of the Trust’s contractual obligations and commitments as at December 31, 2007:
|
| Payments Due by Period ($millions) |
| ||||||||
|
| 2008 |
| 2009-2010 |
| 2011-2012 |
| Thereafter |
| Total |
|
Debt repayments (1) |
| 5.9 |
| 540.8 |
| 51.5 |
| 116.3 |
| 714.5 |
|
Interest payments (2) |
| 11.0 |
| 20.2 |
| 15.5 |
| 13.7 |
| 60.4 |
|
Reclamation fund contributions (3) |
| 5.8 |
| 10.2 |
| 8.9 |
| 71.9 |
| 96.8 |
|
Purchase commitments |
| 10.1 |
| 4.1 |
| 4.0 |
| 6.0 |
| 24.2 |
|
Operating leases (4) |
| 6.2 |
| 8.9 |
| 12.4 |
| 88.1 |
| 115.6 |
|
Risk management contract premiums (5) |
| 13.2 |
| 2.3 |
| — |
| — |
| 15.5 |
|
Total contractual obligations |
| 52.2 |
| 586.5 |
| 92.3 |
| 296.0 |
| 1,027.0 |
|
(1) Long-term and short-term debt, excluding interest.
(2) Fixed interest payments on senior secured notes.
(3) Contribution commitments to a restricted reclamation fund associated with the Redwater property acquired in 2005.
(4) Includes an available option expiring February 2008 to reduce a portion of office lease commitments.
29
(5) Fixed premiums to be paid in future periods on certain risk management contracts.
The above noted risk management contract premiums are part of the Trust’s commitments related to its risk management program. In addition to the above premiums, the Trust has commitments related to its risk management program (see Note 11). As the premiums are part of the underlying risk management contract, they have been recorded at fair market value at December 31, 2007 on the balance sheet as part of risk management contracts.
The Trust enters into commitments for capital expenditures in advance of the expenditures being made. At a given point in time, it is estimated that the Trust has committed to capital expenditures equal to approximately one quarter of its capital budget by means of giving the necessary authorizations to incur the capital in a future period. The Trust’s 2008 capital budget has been approved by the Board at $395 million. This commitment has not been disclosed in the commitment table as it is of a routine nature and is part of normal course of operations for active oil and gas companies and trusts.
The Trust is involved in litigation and claims arising in the normal course of operations. Management is of the opinion that pending litigation will not have a material adverse impact on the Trust’s financial position or results of operations and therefore the following table does not include any commitments for outstanding litigation and claims.
The Trust has certain sales contracts with aggregators whereby the price received by the Trust is dependent upon the contracts entered into by the aggregator. This commitment has not been disclosed in the commitment table as it is of a routine nature and is part of normal course of operations.
22. Differences Between Canadian and United States Generally Accepted Accounting Principles
The consolidated financial statements have been prepared in accordance with Canadian GAAP, which differs in some respects from US GAAP. Any differences in accounting principles as they pertain to the accompanying consolidated financial statements are immaterial except as described below:
The application of US GAAP would have the following effect on net income as reported for the years ended December 31, 2007 and December 31, 2006.
|
| 2007 |
| 2006 |
| ||
Net income as reported for Canadian GAAP |
| $ | 495.3 |
| $ | 460.1 |
|
Adjustments: |
|
|
|
|
| ||
Depletion and depreciation (a) |
| 13.7 |
| 15.8 |
| ||
Unit based compensation (b) |
| (0.4 | ) | (1.6 | ) | ||
Non-controlling interest (d) |
| 6.8 |
| 6.6 |
| ||
Effect of applicable income taxes on the above adjustments and rate change (h) |
| 11.7 |
| (0.3 | ) | ||
Deferred income tax expense (i) |
| (0.1 | ) | — |
| ||
Net income under US GAAP before adoption of accounting policy |
| 527.0 |
| 480.6 |
| ||
Cumulative adjustment related to change in accounting policy (b) |
| — |
| (2.6 | ) | ||
Net income under US GAAP |
| $ | 527.0 |
| $ | 478.0 |
|
|
|
|
|
|
| ||
Net income per Trust unit (Note 20) |
|
|
|
|
| ||
|
|
|
|
|
| ||
Before cumulative adjustment related to change in accounting policy |
|
|
|
|
| ||
Basic (e) |
| $ | 2.51 |
| $ | 2.35 |
|
Diluted (e) |
| $ | 2.50 |
| $ | 2.34 |
|
|
|
|
|
|
| ||
After cumulative adjustment related to change in accounting policy |
|
|
|
|
| ||
Basic (e) |
| $ | 2.51 |
| $ | 2.34 |
|
Diluted (e) |
| $ | 2.50 |
| $ | 2.33 |
|
|
|
|
|
|
| ||
Comprehensive income: |
|
|
|
|
| ||
Net income under US GAAP |
| $ | 527.0 |
| $ | 478.0 |
|
Other comprehensive (loss) income |
| (6.6 | ) | 4.5 |
| ||
Comprehensive income (c) |
| $ | 520.4 |
| $ | 482.5 |
|
30
The application of US GAAP would have the following effect on the Consolidated Balance Sheets as reported:
|
| 2007 |
| 2006 |
| ||||||||
|
| Canadian |
| US |
| Canadian |
| US |
| ||||
|
| GAAP |
| GAAP |
| GAAP |
| GAAP |
| ||||
Property, plant and equipment (a) |
| $ | 3,143.0 |
| $ | 3,039.9 |
| $ | 3,093.8 |
| $ | 2,977.0 |
|
Accounts payable and accrued liabilities (i) |
| (180.6 | ) | (181.0 | ) | (162.1 | ) | (162.1 | ) | ||||
Risk management contracts (c) |
| (68.0 | ) | (68.0 | ) | (8.7 | ) | (3.5 | ) | ||||
Trust unit rights liability (b),(f) |
| — |
| (2.5 | ) | — |
| (3.6 | ) | ||||
Future income taxes/Deferred income taxes (h) |
| (312.2 | ) | (277.2 | ) | (434.2 | ) | (412.3 | ) | ||||
Non-controlling interest (d) |
| (43.1 | ) | — |
| (40.0 | ) | — |
| ||||
Temporary equity (b), (d), (f), (g) |
| — |
| (3,973.7 | ) | — |
| (3,822.1 | ) | ||||
Unitholders’ capital (g) |
| (2,465.7 | ) | — |
| (2,349.2 | ) | — |
| ||||
Contributed surplus (b), (f) |
| (1.7 | ) | — |
| (2.4 | ) | — |
| ||||
Deficit (g) |
| 465.9 |
| 2,000.1 |
| 463.2 |
| 1,990.7 |
| ||||
Accumulated other comprehensive loss (income) (c) |
| 2.9 |
| 2.9 |
| — |
| (3.7 | ) | ||||
The above noted differences between Canadian GAAP and US GAAP are the result of the following:
(a) The Trust performs an impairment test that limits net capitalized costs to the discounted estimated future net revenue from proved and risked probable oil and natural gas reserves plus the cost of unproved properties less impairment, using forward prices. For Canadian GAAP the discount rate used must be equal to a risk free interest rate. Under US GAAP, companies using the full cost method of accounting for oil and gas producing activities perform a ceiling test on each cost centre using discounted estimated future net revenue from proved oil and gas reserves using a discount rate of 10 per cent. Prices used in the US GAAP ceiling tests are those in effect at year-end. The amounts recorded for depletion and depreciation have been adjusted in the periods following the additional write-downs taken under US GAAP to reflect the impact of the reduction of depletable costs.
A US GAAP difference also exists relating to the basis of measurement of proved reserves that is utilized in the depletion calculation. Under US 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.
(b) On January 1, 2006, the Trust adopted Statement of Accounting Standards (“SFAS”) 123R, “Share-Based Payment” using the modified prospective application of this standard and adopted the fair value method of accounting for the rights plan for all rights granted under the plan.
Previously, under US GAAP, the rights plan was accounted for as a variable award under APB 25 and was intrinsically valued at each reporting period. Under SFAS 123R, rights granted under the rights plan are considered liability awards and must be fair valued at each reporting date. On adoption of SFAS 123R, the Trust recorded a charge of $2.6 million for the cumulative effect of this change in accounting policy, which represented the difference between the intrinsic value of the plan at December 31, 2005 and the fair value at January 1, 2006. The Trust also recorded a trust unit rights liability of $16.5 million and an increase to the deficit of $13.9 million, representing the fair value of all outstanding rights in proportion to the requisite service period rendered at January 1, 2006 and the previously recognized compensation expense for all outstanding rights, respectively.
Changes in fair values between periods are charged or credited to net income with a corresponding change in the trust unit
rights liability.
Under Canadian GAAP, the rights plan is treated as an equity award with the initial fair value calculated upon grant date. The fair value is then recorded to compensation expense and credited to contributed surplus over the vesting period of the rights. Upon any rights exercises, the fair value recorded in contributed surplus is reclassified to unitholders’ capital.
The Trust’s Whole Unit Plan is also accounted for in accordance with FAS 123R. Under Canadian GAAP the plan is intrinsically valued. There is, however, no US GAAP difference as terms of the plan result in the fair value of the plan equaling the intrinsic value.
31
(c) US GAAP requires that all derivative instruments (including derivative instruments embedded in other contracts), as defined, be recorded on the Consolidated Balance Sheet as either an asset or liability measured at fair value and requires that changes in fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Hedge accounting treatment under US GAAP allows unrealized gains and losses to be deferred in other comprehensive income (for the effective portion of the hedge) until such time as the forecasted transaction occurs, and requires that a company formally document, designate, and assess the effectiveness of derivative instruments that receive hedge accounting treatment. Prior to January 1, 2007 under Canadian GAAP, derivative instruments that met these specific hedge accounting criteria were not recorded on the Consolidated Balance Sheet and the related unrealized gains and losses were not recorded on the Consolidated Statement of Income and Deficit.
On January 1, 2007, the Trust adopted CICA Handbook Section 3865 – Hedges. As a result, there are no longer US and Canadian GAAP differences relating to hedge accounting that affect the Trust as at December 31, 2007.
The Trust formally documents and designates all hedging relationships and verifies that its hedging instruments were effective in offsetting changes in actual prices and rates received by the Trust. Hedge effectiveness is monitored and any ineffectiveness is reported in the Consolidated Statement of Income and Deficit.
A reconciliation of the components of accumulated other comprehensive income related to all derivative positions is as follows:
|
| 2007 |
| 2006 |
| ||||||||
|
| Gross |
| After Tax |
| Gross |
| After Tax |
| ||||
Accumulated other comprehensive gain (loss), beginning of year |
| 5.2 |
| 3.7 |
| (1.2 | ) | (0.8 | ) | ||||
Unrealized (losses) gains on financial instruments designated as cash flow hedges |
| (8.6 | ) | (6.5 | ) | 6.4 |
| 4.5 |
| ||||
Net unrealized losses on available-for-sale reclamation funds’ investments |
| (0.2 | ) | (0.1 | ) | — |
| — |
| ||||
Accumulated other comprehensive (loss) gain, end of year |
| $ | (3.6 | ) | $ | (2.9 | ) | $ | 5.2 |
| $ | 3.7 |
|
(d) Under Canadian GAAP, ARL Exchangeable Shares are classified as non-controlling interest to reflect a minority ownership in one of the Trust’s subsidiaries. As these exchangeable shares must ultimately be converted into Trust Units, the exchangeable shares are classified as temporary equity along with the Trust Units for US GAAP purposes using the exchange ratio.
(e) Under Canadian GAAP, basic net income per unit is calculated based on net income after non-controlling interest divided by weighted average trust units and diluted net income per unit is calculated based on net income before non-controlling interest divided by dilutive trust units. Under US GAAP, as the exchangeable shares are classified in the same manner as the trust units with no non-controlling interest treatment, basic net income per unit is calculated based on net income divided by weighted average trust units and the trust unit equivalent of the outstanding exchangeable shares. Diluted net income per unit is calculated based on net income divided by a sum of the weighted average trust units, the trust unit equivalent of the outstanding exchangeable shares, and the dilutive impact of rights.
(f) Under Canadian GAAP, compensation expense relating to the rights plan is credited to contributed surplus. For US GAAP compensation expense relating to the rights plan is credited to Trust units rights liability. Once the rights are exercised this amount is classified to temporary equity.
(g) Under US GAAP, as the Trust Units are redeemable at the option of the unitholder, the Trust Units must be recorded at their redemption amount and presented as temporary equity in the Consolidated Balance Sheet. The redemption amount is determined based on the lower of the closing market price on the balance sheet date or 90 percent of the weighted average trading price for the 10 day trading period commencing on the balance sheet date of the Trust Units and the Trust Unit equivalent of the exchangeable shares outstanding. Under Canadian GAAP, all Trust Units are classified as permanent equity. As at December 31, 2007 and 2006, the Trust has classified $4.0 billion and $3.8 billion, respectively, as temporary equity in accordance with US GAAP. Changes in redemption value between periods are charged or credited to deficit. For the period ended December 31, 2007 $38 million was charged to deficit ($1.4 billion credited for the year ending December 31, 2006).
(h) During 2007, legislation was passed whereby distributions paid by the Trust will be subject to tax beginning in 2011. As a result, the deferred tax position of the Trust, the parent entity, is now required to be reflected in the consolidated deferred income tax calculation for US and Canadian GAAP purposes. A one time recovery of $21.9 million was booked for US GAAP purposes relating to ceiling test write-downs made in prior periods which were not previously income tax affected at the Trust level. An additional deferred income tax expense of $6.5 million has also been recorded due to the decrease in the deferred income tax rate in a taxable entity. The remaining amount, $3.7 million is relating to deferred income tax expense recorded on DD&A adjustments for ceiling test writedowns taken in prior periods under US GAAP.
(i) Effective January 1, 2007, the Trust adopted Financial Accounting Standards Board (FASB) Interpretation No. 48 (FIN 48), “Accounting for
32
Uncertainty in Income Taxes”. FIN 48 is an interpretation of SFAS 109, “Accounting for Income Taxes” and prescribes a comprehensive model for recognizing, measuring, presenting and disclosing uncertain tax positions that the Trust has taken or expects to take in its income tax returns. Upon the adoption of FIN 48, the Trust recorded a charge to deficit of $0.3 million, with a corresponding increase in its accounts payable.
During 2007, the Trust recorded an additional charge of $0.1 million for uncertain tax positions for the current year including accrued interest and penalties, which were nominal. As at December 31, 2007, the total amount of our unrecognized tax benefits was approximately $1 million, all of which, if recognized, would affect the Trust’s effective tax rate.
The income tax filings are subject to audit by taxation authorities. The following tax years remained subject to examination as at December 31, 2007, all of which are in Canadian jurisdictions: (i) ARC Energy Trust – 2000 to date, (ii) ARC Resources Ltd. – 2000 to date and (iii) ARC Oil & Gas Fund – 2000 to date. We do not anticipate any material changes to the unrecognized tax benefits previously disclosed within the next twelve months.
(j) In 2007 and 2006, the FASB issued new and revised standards, all of which were assessed by Management to be not applicable to the Trust with the exception of the following:
· In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements, to increase consistency and comparability in fair value measurements and to expand their disclosures. The new standard includes a definition of fair value as well as a framework for measuring fair value. The standard was set to be effective for fiscal periods beginning after November 15, 2007. On December 14, 2007, the FASB issued proposed FSP FAS 157-b to defer Statement 157’s effective date for all nonfinancial assets and liabilities, except those items recognized or disclosed at fair value on an annual or more frequently recurring basis, until years beginning after November 15, 2008. This standard should be applied prospectively, except for certain financial instruments where it must be applied retroactively as a cumulative-effect adjustment to the balance of opening retained earnings in the year of adoption. The Trust is currently evaluating the impact of this standard on its financial statements.
· On February 15, 2007, the FASB issued Statement No. 159, The Fair Value Option for Financial Assets and Liabilities (SFAS 159). FAS 159 provides an entity the option to report selected financial assets and liabilities at fair value and establishes new disclosure requirements for assets and liabilities to which the fair value option is applied. The standard is effective for fiscal periods beginning after November 15, 2007. The standard requires prospective application except when an entity elects the fair value option for items existing as of the date of adoption; the difference between the carrying amount and the fair value should be included in a cumulative effect adjustment to the opening balance of retained earnings. The Trust is currently evaluating the impact of this standard on its financial statements.
· In December 2007, FASB issued Statement No. 141(R), Business Combinations and Statement No. 160, Non-controlling Interests in Consolidated Financial Statements. These statements require: more assets and liabilities assumed to be measured at fair values as of the acquisition date; liabilities related to contingent consideration to be remeasured at fair value in each subsequent reporting period; an acquirer in pre-acquisition periods to expense all acquisition-related costs; and non-controlling interests in subsidiaries initially to be measured at fair value and classified as a separate component of equity. SFAS 141(R) and 160 are effective for fiscal years beginning on or after December 15, 2008. The standard should be applied prospectively, with the exception of certain adjustments for income taxes. Statement 160 requires the entity to apply the presentation and disclosure requirements retroactively to comparative financial statements.
33