**Exhibit 99.4**

 

**AUDITORS’ REPORT ON RECONCILIATION TO UNITED STATES GAAP**

** **

To the Boardof Directors of Penn West Petroleum Ltd., the administrator of Penn West EnergyTrust

 

On March 26,2009, we reported on the consolidated balance sheets of Penn West EnergyTrust (the “Trust”) as at December 31, 2008 and 2007 and theconsolidated statements of operations and retained earnings and cash flows forthe years then ended, which are included in the annual report on Form 40-F.  In connection with our audits of the aforementionedconsolidated financialstatements, we also have audited the related supplemental note entitled “Reconciliationof Canadian and United States Generally Accepted Accounting Principles”. Thissupplemental note is the responsibility of the Trust’s management. Ourresponsibility is to express an opinion on this supplemental note based on ouraudits.

 

In ouropinion, such supplemental note, when considered in relation to the basicconsolidated financial statements taken as a whole, presents fairly, in allmaterial respects, the information set forth therein.

 

[signed]“KPMG LLP”

CharteredAccountants

Calgary,Canada

March 26,2009

 

----

 

**Reconciliation of Canadian and UnitedStates Generally Accepted Accounting Principles**

 

Canadian Generally Accepted Accounting Principles (“GAAP”)vary in certain respects from U.S. GAAP. As required by the United StatesSecurities and Exchange Commission, the effect of these differences inprinciples on Penn West Energy Trust’s (the “Trust”) consolidated financialstatements is described and quantified below:

 

The application of U.S. GAAP would have the followingeffects 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 followingeffects 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 onthe statement of cash flows.

 

**(a) Property, plant andequipment and depletion and depreciation**

 

Under Canadian GAAP, an impairment exists when the netbook value of the petroleum and natural gas properties exceed the sum of theundiscounted future cash flows from proved reserves calculated using forecastprices and costs, and the cost of unproved properties. If an impairment isdetermined to exist, the impairment is measured as the amount by which the netbook value of the petroleum and natural gas properties exceeds the sum of thepresent value of future cash flows from proved plus probable reserves usingforecast prices and costs, and the lower of cost and net realizable value ofunproved properties.

 

Under U.S. GAAP, the net book value of petroleum andnatural gas properties, net of deferred income taxes, is limited to the presentvalue of after-tax future net cash flows from proved reserves, discounted at 10percent and using prices and costs at the balance sheet date, plus the lower ofcost and net realizable value of unproved properties. The impairment test isperformed quarterly and, if elected by the Trust, recalculated seven businessdays prior to the filing date of the Trust’s consolidated financial statementsif an impairment was indicated on the balance sheet date. If there is an impairmentindicated at the balance sheet date, which no longer exists at the time of thesecond test, no write down is required. At December 31, 2008 an impairmentof $6,180 million was indicated and resulted in a write-down of capitalizedcosts (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 wereused to calculate the future net revenues.

 

Depletion and depreciation of resource properties iscalculated using the unit-of-production method based on production volumesbefore royalties in relation to proved reserves as estimated by independentpetroleum engineers. In determining the depletable base, the estimated futurecosts to be incurred in developing proved reserves are included and theestimated equipment salvage values and the lower of cost and market ofunevaluated properties is excluded. Significant natural gas processingfacilities, net of estimated salvage values, are depreciated using thedeclining balance method. Depletion and depreciation per gross equivalentbarrel is calculated by converting natural gas volumes to barrels of oilequivalent (“BOE”) using a ratio of 6 mcf of natural gas to one barrel of crudeoil. As a result of using proved reserves and prices and costs at the balancesheet date an increase in depletion and depreciation under U.S. GAAP totalling$33 million was charged to income for 2008 (2007 - $nil). Depletion anddepreciation 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 thedepletion and depreciation difference.

 

**(b) Unitholders’ mezzanineequity**

 

U.S. GAAP requires that trust units, which areredeemable at the option of the unitholder, be valued at their redemptionamount and presented as temporary equity on the balance sheet. The redemptionvalue of the Penn West trust units is determined based on 95% of the marketvalue of the trust units at each balance sheet date. Under Canadian GAAP, alltrust units are classified as unitholders’ equity. As at December 31,2008, the Trust reclassified $4,983 million (December 31, 2007 - $5,957million) as unitholders’ mezzanine equity in accordance with U.S. GAAP.

 

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

 

**(c) Unit-based compensation**

 

Under U.S. GAAP, the trust unit rights are a liabilitywhich is calculated based on the fair value of the grants, determined by theBinomial Lattice model at each reporting date until the date of settlement.Compensation cost is recorded based on the change in fair value of the rightsduring each reporting period.  Whenrights are exercised, the proceeds received plus the amount recorded as a trustunit rights liability are recorded as mezzanine equity. The Trust issues unitsfrom treasury to settle unit rights exercises.

 

----

 

Rights granted under the rights plan are consideredequity 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 incomeover the vesting period of the rights with a corresponding increase incontributed surplus. When rights are exercised, consideration received plus thefair value recorded in contributed surplus is transferred to unitholders’equity. Contributed surplus amounts are not recognized under U.S. GAAP. UnderU.S. GAAP, for the year ended 2008, compensation cost calculated was $71million lower (2007 - $29 million) than compensation cost calculated underCanadian 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. GAAPcompensation cost related to trust unit rights non-vested and thus not recordedwas $106 million (2007 - $62 million), which on a weighted average basis isexpected to be charged to income over the next 2.1 years (2007 – 2.7 years). Asat December 31, 2008, the fair value of trust units vested during the yearwas $19 million (2007 - $9 million) with a weighted average remaining life of 1.2years (2007 – 2.8 years). If certain conditions are met, exercise prices areadjusted for distributions. Assuming these conditions are met, the totalintrinsic value at December 31, 2008 for trust unit rights outstanding was$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, adifference exists in the diluted weighted average number of trust unitsconsidered outstanding under U.S. GAAP. The U.S. GAAP amount included asproceeds on assumed exercises of unit rights is based on the fair value at eachbalance sheet date, compared to the fair value at only the date of grant underCanadian GAAP, resulting in a different number of units included in the perunit calculations. For the year ended December 31, 2008, 15.8 milliontrust unit rights (2007 – 6.7 million) and 5.7 million units that would beissued on the conversion of the convertible debentures (2007 – nil) wereexcluded in calculating the weighted average number of diluted trust unitsoutstanding as they were considered anti-dilutive under U.S. GAAP.

 

**(d) Acquisitions**

 

**Canetic/ Vault/ Endev**

 

Penn West accounted forthe Canetic Resources Trust (“Canetic”), Vault Energy Trust (“Vault”) and EndevEnergy Inc. (“Endev”) acquisitions as purchases. The consolidated financialstatements of Penn West include the results of operations, funds flow and netincome of Canetic from the closing date of January 11, 2008, of Vault fromthe closing date of January 10, 2008 and of Endev from the closing date ofJuly 22, 2008. If the acquisitions had occurred on January 1, 2008and 2007, Penn West would have realized the following U.S. GAAP pro formaresults 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, theTrust presents oil and natural gas revenues and royalty income prior toroyalties payable in the Consolidated Statement of Operations and RetainedEarnings. Under U.S. GAAP, these items would be combined and presented on a netbasis in the Consolidated Statement of Operations and Retained Earnings.

 

----

 

**(f) Income Taxes**

 

On January 1, 2007, theTrust adopted FASB Interpretation 48 “Accounting for Uncertainty in IncomeTaxes” regarding the accounting for uncertainty in income taxes recognized inan enterprise’s financial statements in accordance with FASB Statement No. 109“Accounting for Income Taxes”. This Interpretation prescribes a recognition threshold and measurementattribute for the financial statement recognition and measurement of a taxposition taken or expected to be taken in a tax return. It also providesguidance on de-recognition, classification, interest and penalties, accountingin interim periods, disclosure, and transition. The adoption of FIN 48 did nothave 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 $10million including $3 million of interest and penalties, which if recognizedwould affect the Trust’s effective income tax rate. The resolution of these taxpositions may take a number of years to complete with the appropriate taxauthorities, thus fluctuations could occur from period to period.

 

The change in the amount ofunrecognized 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 entitiesare subject to income taxation and related audits in Canada. The tax years from2002 to 2008 remain open to audit by Canadian tax authorities.

 

**Accountingchanges**

 

In February 2007, the FASB issued SFAS No. 159, “TheFair Value Option for Financial Assets and Financial Liabilities—Including anAmendment of FASB Statement No. 115.” This pronouncement permitsentities to use the fair value method to measure certain financial assets andliabilities by electing an irrevocable option to use the fair value method atspecified election dates. If the fair value option is elected, subsequentchanges in fair value would result in the recognition of unrealized gains orlosses as period costs, during the period the change occurred. SFAS No. 159became effective for the Trust on January 1, 2008. The provisions of SFAS No. 159may not be retroactively applied to fiscal years preceding the date ofadoption. The adoption ofthis statement had no material impact to the Trust.

 

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

 

Asat December 31, 2008, the only asset or liability measured at fair valueon a recurring basis was the risk management asset and liability, which wasvalued using Level 2 inputs.

 

**Recent U.S.accounting pronouncements**

 

In December 2007, theFASB revised SFAS No. 141R, “Business Combinations”. This Statementoutlines principles for the acquirer on recognizing assets acquired andliabilities assumed in a transaction, establishes the acquisition date fair valuefor all assets and liabilities purchased and the requirement for additionaldisclosures for users of the financial statements to evaluate the businesscombination. The Statement is to be applied prospectively and becomes effectivefor business combinations at the beginning of the first annual reporting periodon or after December 15, 2008. The Trust will implement this guidance onfuture business combinations on or after the effective date.

 

----

 

In December 2007, theFASB issued SFAS No. 160, “Non-Controlling Interests in ConsolidatedFinancial Statements”. This pronouncement requires entities to reportnon-controlling interests as equity in the consolidated financial statements.The Statement is to be applied prospectively and becomes effective for businesscombinations at the beginning of the first annual reporting period on or after December 15,2008. The Trust will implement this guidance, if applicable, on futureacquisitions on or after the effective date.

 

In March 2008, the FASBissued SFAS No. 161, “Disclosures about Derivative Instruments and HedgingActivities”. This is an amendment to the previously issued SFAS No. 133, “Accountingfor Derivative Instruments and Hedging Activities”. This Statement outlinesadditional disclosure requirements for derivative instruments and hedgingactivities to offer further information and transparency to users of thefinancial statements. The Statement is to be applied prospectively and becomeseffective for financial statements issued for fiscal years and interim periodsafter November 15, 2008. The Trust is currently assessing the impact ofSFAS 161.

 

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

 

In December 2008, theSEC approved the previously announced revisions to modernize Oil and GasCompany reporting requirements. These new requirements include a change toreporting oil and gas reserves and completing the impairment test by using anaverage 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 andfor annual reports filed on or after December 31, 2009. The Trust iscurrently assessing the impact of these revisions.

 

**SUPPLEMENTARY OIL AND GAS INFORMATION - FAS69 (UNAUDITED)**

 

Thefollowing disclosures in this section provide oil and gas information inaccordance with the U.S. standard FAS 69, “Disclosures about Oil and GasProducing Activities”.

 

**NETPROVED OIL AND GAS RESERVES**

 

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

 

Netreserves include Penn West’s remaining royalty and working interest reserves,less all Crown, freehold, and overriding royalties and interests that are notowned by Penn West.

 

Provedreserves are those estimated quantities of crude oil, natural gas and naturalgas liquids that can be estimated with a high degree of certainty to beeconomically recoverable under existing economic and operating conditions.

 

Proveddeveloped reserves are those proved reserves that are expected to be recoveredfrom existing wells and installed facilities or, if facilities have not beeninstalled, that would involve a low expenditure to put the reserves onproduction. Proved developed reserves may be subdivided into producing andnon-producing.

 

Provedundeveloped reserves are those reserves that are expected to be recovered fromknown accumulations where a significant expenditure is required to render themcapable of production.

 

----

 

PennWest cautions users of this information as the process of estimating crude oiland natural gas reserves is subject to a level of uncertainty. The reserves arebased on economic and operating conditions; therefore, changes can be made tofuture assessments as a result of a number of factors, which can include newtechnology, 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                      |       |

 

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(1) Columnsmay not add due to rounding.

(2) PennWest does not file any estimates of total net proved crude oil or natural gasreserves with any U.S. federal authority or agency other than the SEC.

 

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**CAPITALIZEDCOSTS**

** **
| **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 |   |

 

**COSTSINCURRED**

 
| **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 |   |

 

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(1) Acquisitionsare net of disposition of properties.

(2) Costof geological and geophysical capital expenditures and drilling costs for explorationwells drilled.

(3) Includesequipping and facilities capital expenditures.

 

**RESULTSOF 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 |   |

 

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(1) PennWest is currently not taxable.

 

**STANDARDIZEDMEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN**

 

Thestandardized measure of discounted future net cash flows is based on estimatesmade by GLJ and Sproule of net proved reserves. Future cash inflows arecomputed based on year-end constant prices and cost assumptions applied againstannual future production from proved crude oil and natural gas reserves. Futuredevelopment and production costs are based on year-end constant priceassumptions and assume the continuation of existing economic conditions. Futureincome taxes are calculated by applying statutory income tax rates. The Trustis currently not taxable. The standardized measure of discounted future netcash flows is computed using a 10 percent discount factor.

 

PennWest cautions users of this information that the discounted future net cashflows relating to proved oil and gas reserves are neither an indication of thefair market value of our oil and gas properties, nor of the future net cashflows expected to be generated from such properties. The discounted future cashflows do not include the fair market value of exploratory properties andprobable or possible oil and gas reserves, nor is consideration given to theeffect of anticipated future changes in crude oil and natural gas prices,development, asset retirement and production costs and possible changes to taxand royalty regulations. The prescribed discount rate of 10 percent isarbitrary and may not appropriately reflect future interest rates.

 

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| **($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 |   |

 

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(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 |   |

 

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(1) Companyactual before income taxes, excluding general and administrative expenses.

(2) Theimpact of changes in prices and other economic factors on future net revenue.

(3) Actualcapital expenditures relating to the exploration, development and production ofoil and gas reserves.

(4) Thechange in forecast development costs.

(5) Endof period net present value of the related reserves.

(6) Estimatedas 10 percent of the beginning of period net present value.

(7) Thedifference between forecast income taxes at beginning of period and the actualtaxes for the period plus forecast income taxes at the end of period.  With the conversion to a trust, Penn Westdoes not currently pay income taxes.

(8) Includeschanges due to revised production profiles, development timing, operatingcosts, royalty rates and actual prices received versus forecast.

 

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