Reconciliation of Canadian and United States Generally Accepted Accounting Principles

Canadian Generally Accepted Accounting Principles (“GAAP”) vary 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:

	Year ended December 31
(CAD millions, except per unit amounts)	2008			2007

Net and Other Comprehensive Income as reported in the
Consolidated Statements of Income - Canadian GAAP	$	1,221		$	175
Adjustments
Unit-based compensation (note (c))	71			29
Impairment charge (note (a))	(6,180		)	—
Depletion & depreciation (note (a))	(33		)	—
Income tax effect of the above adjustments	1,473			—
Net and Other Comprehensive Income (Loss), U.S. GAAP, as adjusted	$	(3,448	)	$	204

Net income (loss) per trust unit, as adjusted
Basic	$	(9.18	)	$	0.85
Diluted	(9.18		)	0.85

Weighted average number of trust units outstanding (millions)
Basic	375.6			239.4
Diluted	377.2			240.7

Deficit - U.S. GAAP
Balance, beginning of the year - U.S. GAAP	$	(1,413	)	$	(2,396	)
Net income (loss) - U.S. GAAP	(3,448		)	204
Change in redemption value of Trust units (note (b))	5,066			1,756
Distributions declared	(1,550		)	(977		)
Balance, end of year - U.S. GAAP	$	(1,345	)	$	(1,413	)

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

	Canadian		U.S.
December 31, 2008 (CAD millions)	GAAP		GAAP

ASSETS
Current
Accounts receivable	$	386	$	386
Risk management	448		448
Other	106		106
	940		940

Property, plant and equipment (note (a))	12,452		6,239
Goodwill	2,020		2,020
Future income tax	—		105
	14,472		8,364
	$	15,412	$	9,304

LIABILITIES AND UNITHOLDERS’ EQUITY (DEFICIENCY)
Current
Accounts payable	$	630	$	630
Distributions payable	132		132
Convertible debentures	7		7
Future income tax	132		132
	901		901
Long-term debt	3,854		3,854
Convertible debentures	289		289
Risk management	6		6
Asset retirement obligations	614		614
Unit rights liability (note (c))	—		2
Future income tax	1,368		—
Total liabilities	7,032		5,666

Unitholders’ mezzanine equity (note (b))	—		4,983

Unitholders’ equity (deficiency)
Unitholders’ capital (note (b))	7,976		—
Contributed surplus (note (c))	75		—
Retained earnings (deficit) (note (b))	329		(1,345		)
	8,380		(1,345		)
	$	15,412	$	9,304

	Canadian		U.S.
December 31, 2007 (CAD millions)	GAAP		GAAP

ASSETS
Current
Accounts receivable	$	277	$	277
Future income tax	45		45
Other	46		46
	368		368
Property, plant and equipment (note (a))	7,413		7,413
Goodwill	652		652
	8,065		8,065
	$	8,433	$	8,433

LIABILITIES AND UNITHOLDERS’ EQUITY (DEFICIENCY)
Current
Accounts payable	$	359	$	359
Distributions payable	82		82
Risk management	148		148
	589		589
Long-term debt	1,943		1,943
Asset retirement obligations	413		413
Unit rights liability (note (c))	—		25
Future income taxes	918		919
Total liabilities	3,863		3,889

Unitholders’ mezzanine equity (note (b))	—		5,957

Unitholders’ equity (deficiency)
Unitholders’ capital (note (b))	3,877		—
Contributed surplus (note (c))	35		—
Retained earnings (deficit) (note (b))	658		(1,413		)
	4,570		(1,413		)
	$	8,433	$	8,433

The application of U.S. GAAP would have no effect on the statement of 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 exceed 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 cash flows from proved plus probable reserves using forecast prices and costs, and the lower of cost and net realizable value 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 net realizable value of unproved properties. The impairment test is performed quarterly and, if 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, 2008 an impairment of $6,180 million was indicated and resulted in a write-down of capitalized costs (2007 - $nil). In the impairment test, prices of $6.28 per mcf (2007 - $6.43) for natural gas and $38.06 per barrel (2007 - $77.91) 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 are 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. 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. As a result of using proved reserves and prices and costs at the balance sheet date an increase in depletion and depreciation under U.S. GAAP totalling $33 million was charged to income for 2008 (2007 - $nil). Depletion and depreciation per BOE as calculated under U.S. GAAP for the year ended December 31, 2008 was $112.04 (2007 - $18.70), which included the impairment charge and the depletion and depreciation difference.

(b) 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, 2008, the Trust reclassified $4,983 million (December 31, 2007 - $5,957 million) as unitholders’ mezzanine equity in accordance with U.S. GAAP.

Changes in unitholders’ mezzanine equity, trust units issued net of redemptions, net income and distributions in a period are recognized as charges to deficit. The Trust recorded a reduction of $5,066 million to deficit for the year ended December 31, 2008, compared to a reduction of $1,756 million for the same period of 2007 to reflect the changes in unitholders’ mezzanine equity.

(c) Unit-based compensation

Under U.S. GAAP, the trust unit rights are a liability which 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 received plus the amount recorded as a trust unit rights liability are recorded as mezzanine equity. The Trust issues units from treasury to settle unit rights exercises.

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. Contributed surplus amounts are not recognized under U.S. GAAP. Under U.S. GAAP, for the year ended 2008, compensation cost calculated was $71 million lower (2007 - $29 million) than compensation cost calculated under Canadian GAAP. The compensation recovery for the year ended 2008 of $26 million (2007 – $8 million) under U.S. GAAP was allocated $19 million (2007 - $6 million) to corporate employees and $7 million (2007 - $2 million) to field employees.

As at December 31, 2008, total U.S. GAAP compensation cost related to trust unit rights non-vested and thus not recorded was $106 million (2007 - $62 million), which on a weighted average basis is expected to be charged to income over the next 2.1 years (2007 – 2.7 years). As at December 31, 2008, the fair value of trust units vested during the year was $19 million (2007 - $9 million) with a weighted average remaining life of 1.2 years (2007 – 2.8 years). If certain conditions are met, exercise prices are adjusted for distributions. Assuming these conditions are met, the total intrinsic value at December 31, 2008 for trust unit rights outstanding was $nil (2007 - $40 million), for trust unit rights exercisable was $nil (2007 - $13 million) and for trust units exercised during the period was $nil (2007 - $4 million).

For purposes of calculating earnings per share, a difference exists in the diluted weighted average number of trust units considered outstanding under U.S. GAAP. The U.S. GAAP amount included as proceeds on assumed exercises of unit rights 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, resulting in a different number of units included in the per unit calculations. For the year ended December 31, 2008, 15.8 million trust unit rights (2007 – 6.7 million) and 5.7 million units that would be issued on the conversion of the convertible debentures (2007 – nil) were excluded in calculating the weighted average number of diluted trust units outstanding as they were considered anti-dilutive under U.S. GAAP.

(d) Acquisitions

Canetic/ Vault/ Endev

Penn West accounted for the Canetic Resources Trust (“Canetic”), Vault Energy Trust (“Vault”) and Endev Energy Inc. (“Endev”) acquisitions as purchases. The consolidated financial statements of Penn West include the results of operations, funds flow and net income of Canetic from the closing date of January 11, 2008, of Vault from the closing date of January 10, 2008 and of Endev from the closing date of July 22, 2008. If the acquisitions had occurred on January 1, 2008 and 2007, Penn West would have realized the following U.S. GAAP pro forma results for the years ended December 31:

(unaudited)	2008			2007
Revenue ($CAD millions)	$	4,127		$	3,362
Net loss ($CAD millions)	(3,454		)	(56		)
Basic per unit	(9.05		)	(0.15		)
Diluted per unit	$	(9.05	)	$	(0.15	)

(e) Additional disclosure

Under Canadian GAAP, the Trust presents oil and natural gas revenues and royalty income prior to royalties payable in the Consolidated Statement of Operations and Retained Earnings. Under U.S. GAAP, these items would be combined and presented on a net basis in the Consolidated Statement of Operations and Retained Earnings.

(f) Income Taxes

On January 1, 2007, the Trust adopted FASB Interpretation 48 “Accounting for Uncertainty in Income Taxes” regarding 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, 2008, the total amount of the Trust’s unrecognized tax benefits was approximately $10 million including $3 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 could occur from period to period.

The change in the amount of unrecognized tax benefits is as follows:

(millions)	2008		2007
Balance, beginning of year	$	9	$	—
Additions/ resolutions for the year	1		9
Balance, end of year	$	10	$	9

The Trust and its entities are subject to income taxation and related audits in Canada. The tax years from 2002 to 2008 remain open to audit by Canadian tax authorities.

Accounting changes

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. If the fair value option is elected, 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 became effective for the Trust on January 1, 2008. The provisions of SFAS No. 159 may not be retroactively applied to fiscal years preceding the date of adoption. The adoption of this statement had no material impact to the Trust.

The Trust adopted the provisions in SFAS 157 “Fair Value Measurements” for its financial assets and liabilities effective January 1, 2008. This Statement outlines fair value as the price that would be received to sell an asset or the amount paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Statement outlines a hierarchy based on input levels. Level 1 inputs are based on quoted prices in active markets that the Trust has the ability to access at the measurement date. Level 2 inputs are based on quoted prices in markets that are not active or based on prices that are observable for the asset or liability. Level 3 inputs are based on unobservable inputs for the asset or liability.

As at December 31, 2008, the only asset or liability measured at fair value on a recurring basis was the risk management asset and liability, which was valued using Level 2 inputs.

Recent U.S. accounting pronouncements

In December 2007, the FASB revised SFAS No. 141R, “Business Combinations”. This Statement outlines principles for the acquirer on recognizing assets acquired 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 for 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 requires entities to report non-controlling interests as equity in the consolidated financial statements. The Statement is to be applied prospectively and becomes effective for 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.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities”. This is an amendment to the previously issued SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”. This Statement outlines additional disclosure requirements for derivative instruments and hedging activities to offer further information and transparency to users of the financial statements. The Statement is to be applied prospectively and becomes effective for financial statements issued for fiscal years and interim periods after November 15, 2008. The Trust is currently assessing the impact of SFAS 161.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles”. This pronouncement outlines a consistent hierarchy to be used in preparing financial statements that are presented in conformity with U.S. GAAP. This Statement is effective 60 days following the approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles”. The Trust is currently assessing the impact of SFAS 162.

In December 2008, the SEC approved the previously announced revisions to modernize Oil and Gas Company reporting requirements. These new requirements include a change to reporting oil and gas reserves and completing the impairment test by using an average price based on the 12-month period instead of using the year-end price. These changes are effective for filings on or after January 1, 2010 and for annual reports filed on or after December 31, 2009. The Trust is currently assessing the impact of these revisions.

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, “Disclosures about Oil and Gas Producing Activities”.

NET PROVED OIL AND GAS RESERVES

Penn West engaged independent qualified reserve evaluators, GLJ Petroleum Consultants Ltd. (“GLJ”) and Sproule Associates Ltd. (“Sproule”), to audit and evaluate the Trust’s evaluation of our proved developed and proved undeveloped oil and gas reserves. As at December 31, 2008, all of Penn West’s oil and gas reserves are located in Canada and the United States. The changes in our net proved reserve quantities are outlined below.

Net reserves include Penn West’s remaining royalty and working interest 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.

Proved developed reserves are those proved 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 to put the reserves on production. Proved 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 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, 2007

CONSTANT PRICES AND COSTS

	Light and		Heavy		Natural		Natural gas		Barrels of Oil
Net Proved Developed and	Medium Oil		Oil		Gas		Liquids		Equivalent
Proved Undeveloped Reserves (1)	(mmbbl)		(mmbbl)		(bcf)		(mmbbl)		(mmboe)
December 31, 2006	170		42		613		14		327
Extensions & Discoveries	—		2		6		—		3
Improved Recovery	2		1		9		—		5
Technical Revisions	6		2		24		—		12
Acquisitions	10		1		28		—		17
Dispositions	—		—		(15	)	—		(3	)
Production	(14	)	(7	)	(90	)	(2	)	(38	)
Change for the year	4		(1	)	(38	)	(2	)	(4	)
December 31, 2007	174		41		575		12		323
Developed	143		40		544		11		286
Undeveloped	31		1		31		1		37
Total (2)	174		41		575		12		323

YEAR ENDED DECEMBER 31, 2008

CONSTANT PRICES AND COSTS

	Light and		Heavy		Natural		Natural gas		Barrels of Oil
Net Proved Developed and	Medium Oil		Oil		Gas		Liquids		Equivalent
Proved Undeveloped Reserves (1)	(mmbbl)		(mmbbl)		(bcf)		(mmbbl)		(mmboe)
December 31, 2007	174		41		575		12		323
Extensions & Discoveries	5		1		20		—		9
Improved Recovery	2		—		4		—		3
Technical Revisions	(13	)	(4	)	19		—		(14	)
Acquisitions	68		9		406		9		153
Dispositions	—		—		(12	)	—		(2	)
Production	(22	)	(8	)	(137	)	(3	)	(56	)
Change for the year	40		(2	)	300		6		93
December 31, 2008	214		39		875		18		416
Developed	180		34		823		17		369
Undeveloped	34		5		52		1		47
Total (2)	214		39		875		18		416

(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)	2008		2007		2006
Proved oil and gas properties	$	17,030	$	10,622	$	9,379
Unproved oil and gas properties	490		303		304
Total capitalized costs	17,520		10,925		9,683
Accumulated depletion and depreciation	11,281		3,512		2,644
Net capitalized costs	$	6,239	$	7,413	$	7,039

COSTS INCURRED

For the years ended December 31, ($CAD millions)	2008			2007		2006
Property acquisition costs (1)
Proved oil and gas properties	$	(50	)	$	422	$	5
Unproved oil and gas properties	128			30		20
Exploration costs (2)	140			102		83
Development costs (3)	780			530		463
Capital expenditures	998			1,084		571
Corporate acquisitions	5,525			21		3,323
Total expenditures	$	6,523		$	1,105	$	3,894

(1) Acquisitions are net of disposition of properties.

(2) Cost of 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)	2008			2007		2006
Oil and gas sales, net of royalties and commodity contracts	$	4,413		$	1,827	$	1,776
Lease operating costs and capital taxes	865			536		441
Transportation costs	34			24		25
Depletion, depreciation and accretion	7,807			897		655
Income taxes (1)	—			—		—
Results of operations	$	(4,293	)	$	370	$	655

(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 and Sproule 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)	2008		2007
Future cash inflows	$	16,030	$	21,597
Future production costs	8,816		7,312
Future development costs	979		674
Undiscounted pre-tax cash flows	6,235		13,611
Future income taxes (1)	—		—
Future net cash flows	6,235		13,611
Less 10% annual discount factor	2,465		6,597
Standardized measure of discounted future net cash flows	$	3,770	$	7,014

(1) Penn West is currently not taxable.

($CAD millions)	2008			2007
Estimated future net revenue at beginning of year	$	7,014		$	5,378
Oil and gas sales during period net of production costs and royalties (1)	(2,865		)	(1,475		)
Changes due to prices and royalties related to forecast production (2)	(3,307		)	2,037
Development costs during the period (3)	936			637
Changes in forecast development costs (4)	(866		)	(617		)
Changes resulting from extensions and improved recovery (5)	106			164
Changes resulting from discoveries (5)	4			18
Changes resulting from acquisitions of reserves (5)	1,393			362
Changes resulting from dispositions of reserves (5)	(22		)	(68		)
Discount factor (6)	701			538
Net change in income tax (7)	—			—
Changes resulting from technical reserves revision	(129		)	258
All other changes (8)	805			(218		)
Estimated future net revenue at end of year	$	3,770		$	7,014

(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 currently pay income taxes.

(8) Includes changes due to revised production profiles, development timing, operating costs, royalty rates and actual prices received versus forecast.