Exhibit 99.4
AUDITORS’ REPORT ON RECONCILIATION TO UNITED STATES GAAP
To the Board of Directors of Penn West Petroleum Ltd., the administrator of Penn West Energy Trust
On March 6, 2008, we reported on the consolidated balance sheets of Penn West Energy Trust as at December 31, 2007 and 2006 and the consolidated statements of income and retained earnings and cash flows for the years then ended, which are included in the annual report on Form 40-F. In connection with our audits of the aforementioned consolidated financial statements, we also have audited the related supplemental note entitled “Reconciliation of Canadian and United States Generally Accepted Accounting Principles” included in the Form 40-F. This supplemental note is the responsibility of the Trust’s management. Our responsibility is to express an opinion on this supplemental note based on our audits.
In our opinion, such supplemental note, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ KPMG LLP
Chartered Accountants
Calgary, Canada
March 6, 2008
Reconciliation of Canadian and United States Generally Accepted Accounting Principles
Canadian Generally Accepted Accounting Principles (“GAAP”) varies in certain respects from U.S. GAAP. As required by the United States Securities and Exchange Commission, the effect of these differences in principles on Penn West Energy Trust’s (the “Trust”) consolidated financial statements is described and quantified below:
The application of U.S. GAAP would have the following effects on reported net income:
|
| Years ended December 31 |
| ||||
(CAD millions, except per unit amounts) |
| 2007 |
| 2006 |
| ||
|
|
|
|
|
| ||
Net income as reported in the Consolidated Statements of Income - Canadian GAAP |
| $ | 175.5 |
| $ | 665.6 |
|
Adjustments |
|
|
|
|
| ||
Unit-based compensation (note (d)) |
| 28.7 |
| (9.6 | ) | ||
Risk management activities (note (b)) |
| — |
| (11.9 | ) | ||
Income tax effect of the above adjustments |
| — |
| 3.6 |
| ||
Net and Other Comprehensive Income, as adjusted before cumulative effect of change in accounting policy |
| 204.2 |
| 647.7 |
| ||
Cumulative effect of change in accounting policy, net of income taxes (note (d)) |
| — |
| (9.2 | ) | ||
Net and Other Comprehensive Income - U.S. GAAP, as adjusted |
| $ | 204.2 |
| $ | 638.5 |
|
|
|
|
|
|
| ||
Net income per trust unit before cumulative effect of change in accounting policy |
|
|
|
|
| ||
Basic |
| $ | 0.85 |
| $ | 3.23 |
|
Diluted |
| 0.85 |
| 3.20 |
| ||
|
|
|
|
|
| ||
Cumulative effect of change in accounting policy |
|
|
|
|
| ||
Basic |
| — |
| (0.05 | ) | ||
Diluted |
| — |
| (0.05 | ) | ||
|
|
|
|
|
| ||
Net income per trust unit |
|
|
|
|
| ||
Basic |
| 0.85 |
| 3.18 |
| ||
Diluted |
| $ | 0.85 |
| $ | 3.15 |
|
|
|
|
|
|
| ||
Weighted average number of trust units outstanding (millions) |
|
|
|
|
| ||
Basic |
| 239.4 |
| 200.8 |
| ||
Diluted |
| 240.7 |
| 202.6 |
| ||
|
|
|
|
|
| ||
Retained earnings (deficit) - U.S. GAAP |
|
|
|
|
| ||
Balance, beginning of period - U.S. GAAP |
| $ | (2,395.8 | ) | $ | (3,723.8 | ) |
Net income - U.S. GAAP |
| 204.2 |
| 638.5 |
| ||
Change in redemption value of trust units (note (c)) |
| 1,756.2 |
| 1,501.3 |
| ||
Distributions declared |
| (977.9 | ) | (811.8 | ) | ||
Balance, end of period - U.S. GAAP |
| $ | (1,413.3 | ) | (2,395.8 | ) |
The application of U.S. GAAP would have the following effects on the reported balance sheets:
|
| Canadian |
| U.S. |
| ||
December 31, 2007 (CAD millions) |
| GAAP |
| GAAP |
| ||
|
|
|
|
|
| ||
ASSETS |
|
|
|
|
| ||
Current |
|
|
|
|
| ||
Accounts receivable |
| $ | 277.5 |
| $ | 277.5 |
|
Future income tax |
| 44.3 |
| 44.3 |
| ||
Other |
| 45.7 |
| 45.7 |
| ||
|
| 367.5 |
| 367.5 |
| ||
Property, plant and equipment (note (a)) |
| 7,413.5 |
| 7,413.5 |
| ||
Goodwill |
| 652.0 |
| 652.0 |
| ||
|
| 8,065.5 |
| 8,065.5 |
| ||
|
| $ | 8,433.0 |
| $ | 8,433.0 |
|
|
|
|
|
|
| ||
LIABILITIES AND UNITHOLDERS’ EQUITY (DEFICIENCY) |
|
|
|
|
| ||
Current |
|
|
|
|
| ||
Accounts payable |
| $ | 359.3 |
| $ | 359.3 |
|
Distributions payable |
| 82.5 |
| 82.5 |
| ||
Risk management (note (b)) |
| 147.6 |
| 147.6 |
| ||
|
| 589.4 |
| 589.4 |
| ||
Long-term debt |
| 1,943.2 |
| 1,943.2 |
| ||
Asset retirement obligations |
| 413.5 |
| 413.5 |
| ||
Unit rights liability (note (d)) |
| — |
| 24.8 |
| ||
Future income taxes |
| 917.4 |
| 918.5 |
| ||
Total liabilities |
| 3,863.5 |
| 3,889.4 |
| ||
|
|
|
|
|
| ||
Unitholders’ mezzanine equity (note (c)) |
| — |
| 5,956.9 |
| ||
|
|
|
|
|
| ||
Unitholders’ Equity (Deficiency) |
|
|
|
|
| ||
Unitholders’ capital (note (c)) |
| 3,877.1 |
| — |
| ||
Contributed surplus (note (d)) |
| 35.3 |
| — |
| ||
Retained earnings (deficit) (note (c)) |
| 657.1 |
| (1,413.3 | ) | ||
|
| 4,569.5 |
| (1,413.3 | ) | ||
|
| $ | 8,433.0 |
| $ | 8,433.0 |
|
|
| Canadian |
| U.S. |
| ||
December 31, 2006 (CAD millions) |
| GAAP |
| GAAP |
| ||
|
|
|
|
|
| ||
ASSETS |
|
|
|
|
| ||
Current |
|
|
|
|
| ||
Accounts receivable |
| $ | 268.7 |
| $ | 268.7 |
|
Risk management (note (b)) |
| 54.0 |
| 54.0 |
| ||
Other |
| 56.0 |
| 56.0 |
| ||
|
| 378.7 |
| 378.7 |
| ||
Property, plant and equipment (note (a)) |
| 7,039.0 |
| 7,039.0 |
| ||
Goodwill |
| 652.0 |
| 652.0 |
| ||
|
| 7,691.0 |
| 7,691.0 |
| ||
|
| $ | 8,069.7 |
| $ | 8,069.7 |
|
|
|
|
|
|
| ||
LIABILITIES AND UNITHOLDERS’ EQUITY (DEFICIENCY) |
|
|
|
|
| ||
Current |
|
|
|
|
| ||
Accounts payable |
| $ | 384.1 |
| $ | 384.1 |
|
Distributions payable |
| 80.6 |
| 80.6 |
| ||
|
| 464.7 |
| 464.7 |
| ||
Long-term debt |
| 1,285.0 |
| 1,285.0 |
| ||
Asset retirement obligations |
| 339.1 |
| 339.1 |
| ||
Unit rights liability (note (d)) |
| — |
| 34.1 |
| ||
Future income taxes |
| 792.6 |
| 793.7 |
| ||
Total liabilities |
| 2,881.4 |
| 2,916.6 |
| ||
|
|
|
|
|
| ||
Unitholders’ mezzanine equity (note (c)) |
| — |
| 7,548.9 |
| ||
|
|
|
|
|
| ||
Unitholders’ Equity (Deficiency) |
|
|
|
|
| ||
Unitholders’ capital (note (c)) |
| 3,712.4 |
| — |
| ||
Contributed surplus (note (d)) |
| 16.4 |
| — |
| ||
Retained earnings (deficit) (note (c)) |
| 1,459.5 |
| (2,395.8 | ) | ||
|
| 5,188.3 |
| (2,395.8 | ) | ||
|
| $ | 8,069.7 |
| $ | 8,069.7 |
|
The application of U.S. GAAP would have no effects on reported cash flows.
(a) Property, plant and equipment and depletion and depreciation
Under Canadian GAAP, an impairment exists when the net book value of the petroleum and natural gas properties exceeds the sum of the undiscounted future cash flows from proved reserves calculated using forecast prices and costs, and the cost of unproved properties. If an impairment is determined to exist, the impairment is measured as the amount by which the net book value of the petroleum and natural gas properties exceeds the sum of the present value of future discounted cash flows from proved plus probable reserves using forecast prices and costs, and the cost of unproved properties.
Under U.S. GAAP, the net book value of petroleum and natural gas properties, net of deferred income taxes, is limited to the present value of after-tax future net cash flows from proved reserves, discounted at 10 percent and using prices and costs at the balance sheet date, plus the lower of cost and fair value of unproved properties. The impairment test is performed quarterly and, as elected by the Trust, recalculated seven business days prior to the filing date of the Trust’s consolidated financial statements if an impairment was indicated on the balance
sheet date. If there is an impairment indicated at the balance sheet date, which no longer exists at the time of the second test, no write down is required. At December 31, 2007, no impairment was indicated. As at December 31, 2006, an impairment of $443.2 million was indicated but upon the re-performance of the test there was no indication of impairment as commodity prices increased from those applied at December 31, 2006. The application of the impairment test under U.S. GAAP did not result in a write-down of capitalized costs in 2007 or 2006. Prices of $6.43 per mcf (2006 - - $7.27) for natural gas and $77.91 per barrel (2006 - $60.25) for liquids were used to calculate the future net revenues.
Depletion and depreciation of resource properties is calculated using the unit-of-production method based on production volumes before royalties in relation to proved reserves as estimated by independent petroleum engineers. In determining the depletable base, the estimated future costs to be incurred in developing proved reserves is included and the estimated equipment salvage values and the lower of cost and market of unevaluated properties is excluded. Significant natural gas processing facilities, net of estimated salvage values, are depreciated using the declining balance method over the estimated useful lives of the facilities. Depletion and depreciation per gross equivalent barrel is calculated by converting natural gas volumes to barrels of oil equivalent (“BOE”) using a ratio of 6 mcf of natural gas to one barrel of crude oil (sulphur volumes have been excluded from the calculation). Depletion and depreciation per BOE as calculated under U.S. GAAP for the year ended December 31, 2007 was $18.70 (2006 - $15.48).
(b) Derivative financial instruments
Effective January 1, 2007, the Trust adopted the new Canadian standards relating to financial instruments. The new guidance substantially harmonizes Canadian GAAP and U.S. GAAP.
Effective July 1, 2005, the Trust elected to discontinue designating derivative instruments as accounting hedges. As a result of this change, a deferred gain on financial instruments of $16.7 million, that represented the fair value of these financial contracts on July 1, 2005, was recognized on the consolidated balance sheet for Canadian GAAP purposes. This deferred gain was amortized to income over the remaining life of the financial contracts. For U.S. GAAP purposes, as the outstanding instruments at the time U.S. GAAP was adopted did not qualify for hedge accounting, all of the Trust’s financial contracts were measured at fair value, with corresponding changes in fair values recognized as unrealized gains or losses in income of the period. For the year ended December 31, 2007, no adjustment (2006 - $11.9 million, $8.3 million net of tax) to income was recorded for U.S. GAAP purposes for the amortization of the deferred gain on financial instruments previously recorded under Canadian GAAP as the balance had been fully amortized by the end of 2006 for Canadian GAAP purposes.
(c) Unitholders’ mezzanine equity
U.S. GAAP requires that trust units, which are redeemable at the option of the unitholder, be valued at their redemption amount and presented as temporary equity on the balance sheet. The redemption value of the Penn West trust units is determined based on 95% of the market value of the trust units at each balance sheet date. Under Canadian GAAP, all trust units are classified as unitholders’ equity. As at December 31, 2007, the Trust reclassified $5,956.9 million (December 31, 2006 - $7,548.9 million) as unitholders’ mezzanine equity in accordance with U.S. GAAP.
Changes in unitholders’ mezzanine equity in excess of trust units issued, net of redemptions, net income and cash distributions in a period are recognized as charges to the deficit. As a result, the Trust recorded a reduction of $1,756.2 million to deficit for the year ended December 31, 2007 compared to a reduction of $1,501.3 million for 2006.
(d) Unit-based compensation
On January 1, 2006, the Trust adopted SFAS 123R, “Share-Based Payment” using the modified prospective method of application and adopted the fair value method of accounting for all grants under the rights plan. Under SFAS 123R, rights granted under the rights plan are considered liability awards whereas they were previously considered equity awards under SFAS 123. As a result of the adoption of SFAS 123R on January 1, 2006 the Trust recorded a trust unit rights liability of $14.7 million, which represented the fair value of all outstanding unit
rights on that date, in proportion to the requisite service period rendered to that date. In addition, contributed surplus was reduced by $5.5 million representing previously recognized compensation cost for all outstanding unit rights for Canadian GAAP purposes, and an expense of $9.2 million was recorded as a cumulative effect of a change in accounting policy.
Under U.S. GAAP, the trust unit rights liability is calculated based on the fair value of the grants, determined by the Binomial Lattice model at each reporting date until the date of settlement. Compensation cost is recorded based on the change in fair value of the rights during each reporting period. When rights are exercised, the proceeds plus the amount recorded as a trust unit rights liability are recorded to mezzanine equity. The Trust issues units from treasury to settle unit rights exercises. Contributed surplus amounts are eliminated under U.S. GAAP.
Rights granted under the rights plan are considered equity awards for Canadian GAAP purposes, a difference from U.S. GAAP. Unit-based compensation is based upon the fair value of rights issued, determined only on the grant date. This initial fair value is charged to income over the vesting period of the rights with a corresponding increase in contributed surplus. When rights are exercised, consideration received plus the fair value recorded in contributed surplus is transferred to unitholders’ equity. Under U.S. GAAP, for the year ended December 31, 2007, compensation cost calculated was $28.7 million lower (2006 - $9.6 million higher) than compensation cost calculated under Canadian GAAP. The compensation recovery for 2007 of $8.2 million (2006 — expense of $20.9 million) under U.S. GAAP was allocated $6.0 million (2006 - $15.7 million) to corporate employees and $2.2 million (2006 - $5.2 million) to field employees.
As at December 31, 2007, total U.S. GAAP compensation cost related to trust unit rights non-vested and not recorded was $61.8 million (2006 - $45.6 million), which on a weighted average is expected to be charged to income over the next 2.7 years (2006 — 3.7 years). As at December 31, 2007, the fair value of trust units vested during the year was $9.4 million (2006 - $2.7 million) with a weighted average remaining life of 2.8 years (2006 — 3.3 years). If certain conditions are met, exercise prices are adjusted for distributions. Assuming these conditions are met, the total intrinsic value at December 31, 2007 for trust unit rights outstanding was $40.1 million (2006 - $95.2 million), for trust unit rights exercisable was $13.2 million (2006 - $14.0 million) and for trust units exercised during the period was $4.2 million (2006 - - $5.2 million).
A difference exists in the diluted weighted average number of trust units outstanding under U.S. GAAP as the unit-based compensation amount included is based on the fair value at each balance sheet date, compared to the fair value at only the date of grant under Canadian GAAP, leading to a change in the number of units included in the diluted calculation.
(e) Acquisitions
Petrofund
Penn West accounted for the Petrofund acquisition as a purchase of Petrofund. The consolidated financial statements of Penn West include the results of operations and cash flows of Petrofund from July 1, 2006 forward. If the acquisition had occurred on January 1, 2006, Penn West would have realized the following pro forma results for the year ended December 31, 2006:
(unaudited) |
| 2006 |
| |
Revenue ($CAD millions) |
| $ | 2,495.8 |
|
Net income ($CAD millions) |
| 750.3 |
| |
Basic net income per unit |
| 3.18 |
| |
Diluted net income per unit |
| $ | 3.15 |
|
(f) Additional disclosure
The Trust presents oil and natural gas revenues and royalty amounts prior to royalties in the Consolidated Statement of Income and Retained Earnings. Under U.S. GAAP, these items would be combined and presented net in the Consolidated Statement of Income and Retained Earnings.
Change in Accounting policies – US GAAP
Income Taxes
On January 1, 2007, the Trust adopted FASB Interpretation 48 “Accounting for Uncertainty in Income Taxes” clarifying the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109 “Accounting for Income Taxes”. This Interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. It also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The adoption of FIN 48 did not have a material impact on our consolidated financial statements.
As at December 31, 2007, the total amount of the Trust’s unrecognized tax benefits was approximately $8.7 million including $2.7 million of interest and penalties, which if recognized would affect the Trust’s effective income tax rate. The resolution of these tax positions may take a number of years to complete with the appropriate tax authorities, thus fluctuations can occur from period to period. The amount of unrecognized tax benefits is not anticipated to significantly change within the next 12 months.
The Trust and its entities are subject to income taxation and related audits in the Canadian tax jurisdiction. The tax years from 2002 to 2007 remain open to examination in Canada.
Recent U.S. accounting pronouncements
In September 2006, the FASB issued SFAS 157, “Fair Value Measurements”. The statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements. The Statement is to be applied prospectively and is effective for financial statements issued for fiscal years beginning after November 15, 2007. Recently, FASB issued FSP FAS 157-2 delaying the effective date of SFAS 157 for non-financial assets and liabilities to fiscal years beginning after November 15, 2008. The Trust is currently assessing the impact of SFAS 157.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB Statement No. 115.” This pronouncement permits entities to use the fair value method to measure certain financial assets and liabilities by electing an irrevocable option to use the fair value method at specified election dates. After election of the option, subsequent changes in fair value would result in the recognition of unrealized gains or losses as period costs during the period the change occurred. SFAS No. 159 becomes effective as of the beginning of the first fiscal year that begins after November 15, 2007, with early adoption permitted. However, entities may not retroactively apply the provisions of SFAS No. 159 to fiscal years preceding the date of adoption. The Trust is currently assessing the impact of SFAS 159.
In December 2007, the FASB revised SFAS No. 141R, “Business Combinations”. This Statement outlines principles for the acquirer on recognizing assets and liabilities assumed in a transaction, establishes the acquisition date fair value for all assets and liabilities purchased and the requirement for additional disclosures for users of the financial statements to evaluate the business combination. The Statement is to be applied prospectively and becomes effective to business combinations at the beginning of the first annual reporting period on or after December 15, 2008. The Trust will implement this guidance on future business combinations on or after the effective date.
In December 2007, the FASB issued SFAS No. 160, “Non Controlling Interests in Consolidated Financial Statements”. This pronouncement required entities to report non-controlling interests as equity in the consolidated financial statements. The Statement is to be applied prospectively and becomes effective to
business combinations at the beginning of the first annual reporting period on or after December 15, 2008. The Trust will implement this guidance, if applicable, on future acquisitions on or after the effective date.
SUPPLEMENTARY OIL AND GAS INFORMATION - FAS 69 (UNAUDITED)
The following disclosures in this section provide oil and gas information in accordance with the U.S. standard FAS 69, “Disclosure about Oil and Gas Producing Activities”.
NET PROVED OIL AND GAS RESERVES
Penn West engaged an independent qualified reserve evaluator, GLJ Petroleum Consultants Ltd. (“GLJ”), to review the Trust’s proved developed and proved undeveloped oil and gas reserves. As at December 31, 2007, all of Penn West’s oil and gas reserves are located in Canada. The changes in our net proved reserve quantities are outlined below.
Net reserves are Penn West royalty and working interest remaining reserves, less all Crown, freehold, and overriding royalties and interests that are not owned by Penn West.
Proved reserves are those estimated quantities of crude oil, natural gas and natural gas liquids that can be estimated with a high degree of certainty to be economically recoverable under existing economic and operating conditions. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
Proved developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production. Developed reserves may be subdivided into producing and non-producing.
Proved undeveloped reserves are those reserves that are expected to be recovered from known accumulations where a significant expenditure (e.g. when compared to the cost of drilling a well) is required to render them capable of production.
Penn West cautions users of this information as the process of estimating crude oil and natural gas reserves is subject to a level of uncertainty. The reserves are based on economic and operating conditions, therefore, changes can be made to future assessments as a result of a number of factors, which can include new technology, changing economic conditions and development activity.
YEAR ENDED DECEMBER 31, 2006
CONSTANT PRICES AND COSTS
|
|
|
|
|
|
|
|
|
| Barrels of |
|
|
| Light and |
| Heavy |
| Natural |
| Natural gas |
| Oil |
|
Net Proved Developed and |
| Medium Oil |
| Oil |
| Gas |
| Liquids |
| Equivalent |
|
Proved Undeveloped Reserves (1) |
| (mbbl) |
| (mbbl) |
| (mmcf) |
| (mbbl) |
| (mboe) |
|
December 31, 2005 |
| 124,051 |
| 45,217 |
| 466,854 |
| 9,580 |
| 256,657 |
|
Extensions & Discoveries |
| 39 |
| 1,804 |
| 16,359 |
| 138 |
| 4,708 |
|
Improved Recovery |
| 1,788 |
| 64 |
| 3,023 |
| 39 |
| 2,395 |
|
Technical Revisions |
| (2,418 | ) | 543 |
| (6,078 | ) | 684 |
| (2,205 | ) |
Acquisitions |
| 57,050 |
| 621 |
| 221,473 |
| 4,291 |
| 98,874 |
|
Dispositions |
| (126 | ) | (214 | ) | (651 | ) | (6 | ) | (454 | ) |
Production |
| (10,884 | ) | (6,435 | ) | (87,789 | ) | (1,165 | ) | (33,116 | ) |
Change for the year |
| 45,449 |
| (3,617 | ) | 146,337 |
| 3,981 |
| 70,202 |
|
December 31, 2006 |
| 169,500 |
| 41,600 |
| 613,191 |
| 13,560 |
| 326,859 |
|
Developed |
| 139,727 |
| 40,067 |
| 578,131 |
| 12,541 |
| 288,691 |
|
Undeveloped |
| 29,773 |
| 1,533 |
| 35,060 |
| 1,019 |
| 38,168 |
|
Total (2) |
| 169,500 |
| 41,600 |
| 613,191 |
| 13,560 |
| 326,859 |
|
YEAR ENDED DECEMBER 31, 2007
CONSTANT PRICES AND COSTS
|
|
|
|
|
|
|
|
|
| Barrels of |
|
|
| Light and |
| Heavy |
| Natural |
| Natural gas |
| Oil |
|
Net Proved Developed and |
| Medium Oil |
| Oil |
| Gas |
| Liquids |
| Equivalent |
|
Proved Undeveloped Reserves (1) |
| (mbbl) |
| (mbbl) |
| (mmcf) |
| (mbbl) |
| (mboe) |
|
December 31, 2006 |
| 169,500 |
| 41,600 |
| 613,191 |
| 13,560 |
| 326,859 |
|
Extensions & Discoveries |
| 182 |
| 1,951 |
| 6,625 |
| 85 |
| 3,322 |
|
Improved Recovery |
| 2,000 |
| 1,555 |
| 8,474 |
| 96 |
| 5,063 |
|
Technical Revisions |
| 6,127 |
| 1,807 |
| 23,901 |
| (51 | ) | 11,867 |
|
Acquisitions |
| 10,452 |
| 1,088 |
| 28,211 |
| 407 |
| 16,649 |
|
Dispositions |
| (338 | ) | (50 | ) | (14,621 | ) | (297 | ) | (3,122 | ) |
Production |
| (13,632 | ) | (7,190 | ) | (90,489 | ) | (1,803 | ) | (37,707 | ) |
Change for the year |
| 4,791 |
| (839 | ) | (37,899 | ) | (1,563 | ) | 3,928 |
|
December 31, 2007 |
| 174,291 |
| 40,761 |
| 575,293 |
| 11,997 |
| 322,931 |
|
Developed |
| 143,715 |
| 39,818 |
| 544,564 |
| 11,251 |
| 285,545 |
|
Undeveloped |
| 30,576 |
| 943 |
| 30,729 |
| 746 |
| 37,386 |
|
Total (2) |
| 174,291 |
| 40,761 |
| 575,293 |
| 11,997 |
| 322,931 |
|
(1) Columns may not add due to rounding.
(2) Penn West does not file any estimates of total net proved crude oil or natural gas reserves with any U.S. federal authority or agency other than the SEC.
CAPITALIZED COSTS
As at December 31, ($CAD millions) |
| 2007 |
| 2006 |
| 2005 |
| |||
Proved oil and gas properties |
| $ | 10,622 |
| $ | 9,379 |
| $ | 5,465 |
|
Unproved oil and gas properties |
| 303 |
| 304 |
| 259 |
| |||
Total capital costs |
| 10,925 |
| 9,683 |
| 5,724 |
| |||
Accumulated depletion and depreciation |
| 3,511 |
| 2,644 |
| 2,009 |
| |||
Net capitalized costs |
| $ | 7,414 |
| $ | 7,039 |
| $ | 3,715 |
|
COSTS INCURRED
For the years ended December 31, ($CAD millions) |
| 2007 |
| 2006 |
| 2005 |
| |||
Property acquisition costs (1) |
|
|
|
|
|
|
| |||
Proved oil and gas properties |
| $ | 422 |
| $ | 5 |
| $ | (6 | ) |
Unproved oil and gas properties |
| 30 |
| 20 |
| 14 |
| |||
Exploration costs (2) |
| 102 |
| 83 |
| 140 |
| |||
Development costs (3) |
| 530 |
| 463 |
| 299 |
| |||
Capital Expenditures |
| 1,084 |
| 571 |
| 447 |
| |||
Corporate acquisitions |
| 21 |
| 3,323 |
| — |
| |||
Total Expenditures |
| $ | 1,105 |
| $ | 3,894 |
| $ | 447 |
|
(1) Acquisitions are net of disposition of properties.
(2) Cost of land acquired, geological and geophysical capital expenditures and drilling costs for exploration wells drilled.
(3) Includes equipping and facilities capital expenditures.
RESULTS OF OPERATIONS OF PRODUCING ACTIVITIES
For the years ended December 31, ($CAD millions) |
| 2007 |
| 2006 |
| 2005 |
| |||
Oil and gas sales, net of royalties and commodity contracts |
| $ | 1,827 |
| $ | 1,776 |
| $ | 1,561 |
|
Lease operating costs and capital taxes |
| 536 |
| 441 |
| 342 |
| |||
Transportation costs |
| 24 |
| 25 |
| 23 |
| |||
Depletion, depreciation and accretion |
| 897 |
| 655 |
| 438 |
| |||
Income taxes (1) |
| — |
| — |
| 54 |
| |||
Results of operations |
| $ | 370 |
| $ | 655 |
| $ | 704 |
|
(1) Penn West is currently not taxable.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN
The standardized measure of discounted future net cash flows is based on estimates made by GLJ of net proved reserves. Future cash inflows are computed based on year-end constant prices and cost assumptions applied against annual future production from proved crude oil and natural gas reserves. Future development and production costs are based on year-end constant price assumptions and assume the continuation of existing economic conditions. Future income taxes are calculated by applying statutory income tax rates. The Trust is currently not taxable. The standardized measure of discounted future net cash flows is computed using a 10 percent discount factor.
Penn West cautions users of this information that the discounted future net cash flows relating to proved oil and gas reserves are neither an indication of the fair market value of our oil and gas properties, nor of the future net cash flows expected to be generated from such properties. The discounted future cash flows do not include the fair market value of exploratory properties and probable or possible oil and gas reserves, nor is consideration given to the effect of anticipated future changes in crude oil and natural gas prices, development, asset retirement and production costs and possible changes to tax and royalty regulations. The prescribed discount rate of 10 percent is arbitrary and may not appropriately reflect future interest rates.
($CAD millions) |
| 2007 |
| 2006 |
| ||
Future cash inflows |
| $ | 21,597 |
| $ | 17,124 |
|
Future production costs |
| 7,312 |
| 6,350 |
| ||
Future development costs |
| 674 |
| 666 |
| ||
Undiscounted pre-tax cash flows |
| 13,611 |
| 10,108 |
| ||
Future income taxes (1) |
| — |
| — |
| ||
Future net cash flows |
| 13,611 |
| 10,108 |
| ||
Less 10% annual discount factor |
| 6,597 |
| 4,730 |
| ||
Standardized measure of discounted future net cash flows |
| $ | 7,014 |
| $ | 5,378 |
|
(1) Penn West is currently not taxable.
($CAD millions) |
| 2007 |
| 2006 |
| ||
Estimated future net revenue at beginning of year |
| $ | 5,378 |
| $ | 4,972 |
|
Oil and gas sales during period net of production costs and royalties (1) |
| (1,475 | ) | (1,277 | ) | ||
Changes due to prices and royalties related to forecast production (2) |
| 2,037 |
| (856 | ) | ||
Development costs during the period (3) |
| 637 |
| 542 |
| ||
Changes in forecast development costs (4) |
| (617 | ) | (544 | ) | ||
Changes resulting from extensions and improved recovery (5) |
| 164 |
| 164 |
| ||
Changes resulting from discoveries (5) |
| 18 |
| 4 |
| ||
Changes resulting from acquisitions of reserves (5) |
| 362 |
| 1,907 |
| ||
Changes resulting from dispositions of reserves (5) |
| (68 | ) | (7 | ) | ||
Discount factor (6) |
| 538 |
| 497 |
| ||
Net change in income tax (7) |
| — |
| — |
| ||
Changes resulting from technical reserves revision |
| 258 |
| (65 | ) | ||
All other changes (8) |
| (218 | ) | 41 |
| ||
Estimated future net revenue at end of year |
| $ | 7,014 |
| $ | 5,378 |
|
(1) Company actual before income taxes, excluding general and administrative expenses.
(2) The impact of changes in prices and other economic factors on future net revenue.
(3) Actual capital expenditures relating to the exploration, development and production of oil and gas reserves.
(4) The change in forecast development costs.
(5) End of period net present value of the related reserves.
(6) Estimated as 10 percent of the beginning of period net present value.
(7) The difference between forecast income taxes at beginning of period and the actual taxes for the period plus forecast income taxes at the end of period. With the conversion to a trust, Penn West does not pay income taxes.
(8) Includes changes due to revised production profiles, development timing, operating costs, royalty rates and actual prices received versus forecast.