**Exhibit 99.4**

** **

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

 

To the Board of Directors of Penn West PetroleumLtd., the administrator of Penn West Energy Trust

 

On March 6, 2008, we reported on theconsolidated balance sheets of Penn West Energy Trust as at December 31,2007 and 2006 and the consolidated statements of income and retained earningsand cash flows for the years then ended, which are included in the annualreport on Form 40-F.  In connectionwith our audits of the aforementioned consolidated financial statements, we also have audited the relatedsupplemental note entitled “Reconciliation of Canadian and United StatesGenerally Accepted Accounting Principles” included in the Form 40-F. Thissupplemental note is the responsibility of the Trust’s management. Ourresponsibility is to express an opinion on this supplemental note based on ouraudits.

 

In our opinion, such supplemental note, whenconsidered in relation to the basic consolidated financial statements taken asa whole, presents fairly, in all material respects, the information set forththerein.

 

 

/s/ KPMG LLP

 

Chartered Accountants

 

Calgary, Canada

 

March 6, 2008

 

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

 

Canadian Generally Accepted Accounting Principles (“GAAP”)varies 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 financial statementsis described and quantified below:

 

The application of U.S. GAAP would have the followingeffects 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 followingeffects 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 onreported 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 exceeds 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 discounted cash flows from proved plus probablereserves using forecast prices and costs, and the cost of unproved 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 fair value of unproved properties. The impairment test is performedquarterly and, as elected by the Trust, recalculated seven business days priorto the filing date of the Trust’s consolidated financial statements if animpairment was indicated on the balance

 

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sheet date. If there is an impairment indicated at thebalance sheet date, which no longer exists at the time of the second test, nowrite down is required. At December 31, 2007, no impairment was indicated.As at December 31, 2006, an impairment of $443.2 million was indicated butupon the re-performance of the test there was no indication of impairment ascommodity prices increased from those applied at December 31, 2006. Theapplication of the impairment test under U.S. GAAP did not result in awrite-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 wereused to calculate the future net revenues.

 

Depletion anddepreciation of resource properties is calculated using the unit-of-productionmethod based on production volumes before royalties in relation to provedreserves as estimated by independent petroleum engineers. In determining thedepletable base, the estimated future costs to be incurred in developing provedreserves is included and the estimated equipment salvage values and the lowerof cost and market of unevaluated properties is excluded. Significant naturalgas processing facilities, net of estimated salvage values, are depreciatedusing the declining balance method over the estimated useful lives of thefacilities. Depletion and depreciation per gross equivalent barrel iscalculated 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 (sulphurvolumes have been excluded from the calculation). Depletion and depreciationper BOE as calculated under U.S. GAAP for the year ended December 31, 2007was $18.70 (2006 - $15.48).

 

**(b) Derivative financialinstruments**

 

Effective January 1, 2007, the Trust adopted thenew Canadian standards relating to financial instruments. The new guidancesubstantially harmonizes Canadian GAAP and U.S. GAAP.

 

Effective July 1, 2005, the Trust elected todiscontinue designating derivative instruments as accounting hedges. As aresult of this change, a deferred gain on financial instruments of $16.7million, that represented the fair value of these financial contracts on July 1,2005, was recognized on the consolidated balance sheet for Canadian GAAPpurposes. This deferred gain was amortized to income over the remaining life ofthe financial contracts. For U.S. GAAP purposes, as the outstanding instrumentsat the time U.S. GAAP was adopted did not qualify for hedge accounting, all ofthe Trust’s financial contracts were measured at fair value, with correspondingchanges in fair values recognized as unrealized gains or losses in income ofthe 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. GAAPpurposes for the amortization of the deferred gain on financial instrumentspreviously recorded under Canadian GAAP as the balance had been fully amortizedby the end of 2006 for Canadian GAAP purposes.

 

**(c) Unitholders’ mezzanineequity**

** **

U.S. GAAP requires that trust units, which are redeemableat the option of the unitholder, be valued at their redemption amount andpresented as temporary equity on the balance sheet. The redemption value of thePenn West trust units is determined based on 95% of the market value of thetrust units at each balance sheet date. Under Canadian GAAP, all trust unitsare classified as unitholders’ equity. As at December 31, 2007, the Trustreclassified $5,956.9 million (December 31, 2006 - $7,548.9 million) asunitholders’ mezzanine equity in accordance with U.S. GAAP. 

 

Changes in unitholders’ mezzanine equity in excess oftrust units issued, net of redemptions, net income and cash distributions in aperiod are recognized as charges to the deficit. As a result, the Trustrecorded 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-BasedPayment” using the modified prospective method of application and adopted thefair value method of accounting for all grants under the rights plan. UnderSFAS 123R, rights granted under the rights plan are considered liability awardswhereas they were previously considered equity awards under SFAS 123. As a resultof the adoption of SFAS 123R on January 1, 2006 the Trust recorded a trustunit rights liability of $14.7 million, which represented the fair value of alloutstanding unit

 

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rights on that date, in proportion to the requisiteservice period rendered to that date. In addition, contributed surplus wasreduced by $5.5 million representing previously recognized compensation costfor 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 accountingpolicy. 

 

Under U.S. GAAP, the trust unit rights liability iscalculated based on the fair value of the grants, determined by the BinomialLattice model at each reporting date until the date of settlement. Compensationcost is recorded based on the change in fair value of the rights during eachreporting period.  When rights areexercised, the proceeds plus the amount recorded as a trust unit rightsliability are recorded to mezzanine equity. The Trust issues units fromtreasury to settle unit rights exercises. Contributed surplus amounts areeliminated under U.S. GAAP.

 

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. Under U.S. GAAP, for the year ended December 31, 2007,compensation cost calculated was $28.7 million lower (2006 - $9.6 millionhigher) than compensation cost calculated under Canadian GAAP. The compensationrecovery 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 employeesand $2.2 million (2006 - $5.2 million) to field employees.

 

As at December 31, 2007, total U.S. GAAPcompensation 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 expectedto 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 fordistributions. Assuming these conditions are met, the total intrinsic value at December 31,2007 for trust unit rights outstanding was $40.1 million (2006 - $95.2million), for trust unit rights exercisable was $13.2 million (2006 - $14.0million) and for trust units exercised during the period was $4.2 million (2006- $5.2 million).

 

A difference exists in the diluted weighted averagenumber of trust units outstanding under U.S. GAAP as the unit-basedcompensation amount included is based on the fair value at each balance sheetdate, 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 apurchase of Petrofund. The consolidated financial statements of Penn Westinclude the results of operations and cash flows of Petrofund from July 1,2006 forward. If the acquisition had occurred on January 1, 2006, PennWest 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       |   |

 

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** **

**(f) Additionaldisclosure**

 

The Trust presents oil andnatural gas revenues and royalty amounts prior to royalties in the ConsolidatedStatement of Income and Retained Earnings. Under U.S. GAAP, these items wouldbe combined and presented net in the Consolidated Statement of Income andRetained Earnings.

 

**Change in Accounting policies – US GAAP**

 

**Income Taxes**

 

On January 1, 2007, the Trust adopted FASBInterpretation 48 “Accounting for Uncertainty in Income Taxes” clarifying theaccounting for uncertainty in income taxes recognized in an enterprise’sfinancial statements in accordance with FASB Statement No. 109 “Accountingfor Income Taxes”. ThisInterpretation prescribes a recognition threshold and measurement attribute forthe financial statement recognition and measurement of a tax position taken orexpected to be taken in a tax return. It also provides guidance onde-recognition, classification, interest and penalties, accounting in interimperiods, disclosure, and transition. The adoption of FIN 48 did not have amaterial 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 ifrecognized would affect the Trust’s effective income tax rate. The resolutionof these tax positions may take a number of years to complete with theappropriate tax authorities, thus fluctuations can occur from period to period.The amount of unrecognized tax benefits is not anticipated to significantlychange within the next 12 months.

 

The Trust and its entities are subject to incometaxation and related audits in the Canadian tax jurisdiction. The tax yearsfrom 2002 to 2007 remain open to examination in Canada.

 

**Recent U.S. accounting pronouncements**

 

In September 2006, the FASB issued SFAS 157, “FairValue Measurements”. The statement defines fair value, establishes a frameworkfor measuring fair value in generally accepted accounting principles andexpands disclosures about fair value measurements. This Statement applies underother accounting pronouncements that require or permit fair value measurements.The Statement is to be applied prospectively and is effective for financialstatements issued for fiscal years beginning after November 15, 2007.Recently, FASB issued FSP FAS 157-2 delaying the effective date of SFAS 157 fornon-financial assets and liabilities to fiscal years beginning after November 15,2008. The Trust is currently assessing theimpact of SFAS 157.

 

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. After election of the option, subsequent changesin fair value would result in the recognition of unrealized gains or losses asperiod costs during the period the change occurred. SFAS No. 159becomes effective as of the beginning of the first fiscal year that beginsafter November 15, 2007, with early adoption permitted. However, entitiesmay not retroactively apply the provisions of SFAS No. 159 to fiscal yearspreceding the date of adoption. The Trust iscurrently assessing the impact of SFAS 159.

 

In December 2007, the FASB revised SFAS No. 141R,“Business Combinations”. This Statement outlines principles for the acquirer onrecognizing assets and liabilities assumed in a transaction, establishes theacquisition date fair value for all assets and liabilities purchased and therequirement for additional disclosures for users of the financial statements toevaluate the business combination. The Statement is to be applied prospectivelyand becomes effective to business combinations at the beginning of the firstannual reporting period on or after December 15, 2008. The Trust willimplement this guidance on future business combinations on or after theeffective date.

 

In December 2007, the FASB issued SFAS No. 160,“Non Controlling Interests in Consolidated Financial Statements”. Thispronouncement required entities to report non-controlling interests as equityin the consolidated financial statements. The Statement is to be appliedprospectively and becomes effective to

 

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business combinations at the beginning of the firstannual reporting period on or after December 15, 2008. The Trust willimplement this guidance, if applicable, on future acquisitions on or after theeffective date.

 

**SUPPLEMENTARYOIL AND GAS INFORMATION - FAS 69 (UNAUDITED)**

 

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

 

**NETPROVED OIL AND GAS RESERVES**

 

PennWest engaged an independent qualified reserve evaluator, GLJ PetroleumConsultants Ltd. (“GLJ”), to review the Trust’s proved developed and provedundeveloped oil and gas reserves. As at December 31, 2007, all of PennWest’s oil and gas reserves are located in Canada. The changes in our netproved reserve quantities are outlined below.

 

Net reserves are PennWest 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 thoseestimated quantities of crude oil, natural gas and natural gas liquids that canbe estimated with a high degree of certainty to be economically recoverableunder existing economic and operating conditions. It is likely that the actualremaining quantities recovered will exceed the estimated proved reserves.

 

Proved developed reservesare those reserves that are expected to be recovered from existing wells andinstalled facilities or, if facilities have not been installed, that wouldinvolve 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 intoproducing and non-producing.

 

Proved undevelopedreserves are those reserves that are expected to be recovered from knownaccumulations where a significant expenditure (e.g. when compared to the costof drilling a well) is required to render them capable 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, 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        |       |

 

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**YEAR ENDEDDECEMBER 31, 2007  **

**CONSTANTPRICES 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                   |       |

 

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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.

 

**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 |   |

 

**COSTSINCURRED**

 
| **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 |   |

 

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(1) Acquisitionsare net of disposition of properties.

(2) Costof land acquired, geological and geophysical capital expenditures and drillingcosts for exploration wells drilled.

(3) Includesequipping and facilities capital expenditures.

 

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**RESULTS OF OPERATIONS OFPRODUCING 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 |   |

 

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(1) PennWest is currently not taxable.

 

**STANDARDIZED MEASURE OFDISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN**

 

Thestandardized measure of discounted future net cash flows is based on estimatesmade by GLJ of net proved reserves. Future cash inflows are computed based onyear-end constant prices and cost assumptions applied against annualfuture production from proved crude oil and natural gas reserves. Futuredevelopment and production costs are based on year-end constant price assumptions and assume the continuation ofexisting economic conditions. Future income taxes are calculated by applyingstatutory income tax rates. The Trust is currently not taxable. The standardizedmeasure of discounted future net cash flows is computed using a 10 percentdiscount 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 the fairmarket value of our oil and gas properties, nor of the future net cash flowsexpected to be generated from such properties. The discounted future cash flowsdo not include the fair market value of exploratory properties and probable orpossible oil and gas reserves, nor is consideration given to the effect ofanticipated future changes in crude oil and natural gas prices, development,asset retirement and production costs and possible changes to tax and royaltyregulations. The prescribed discount rate of 10 percent is arbitrary and maynot 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 |   |

 

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(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 |   |

 

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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 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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