**Exhibit 99.1**

 

****

** **

**PENN WESTENERGY TRUST**

** **

**AnnualInformation Form**

**forthe year ended December 31, 2008**

 

 

**March 26, 2009**

 

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**TABLE OFCONTENTS**

** **
| ** **                                                  | **Page** |
|-------------------------------------------------------------|----------|
|                                                        |     |
| GLOSSARY OF  TERMS                                          | 2        |
| CONVENTIONS                                                 | 5        |
| ABBREVIATIONS                                               | 5        |
| CONVERSIONS                                                 | 7        |
| SPECIAL NOTE  REGARDING FORWARD-LOOKING STATEMENTS          | 8        |
| NON-GAAP  MEASURES                                          | 9        |
| EFFECTIVE DATE  OF INFORMATION                              | 9        |
| PENN WEST  ENERGY TRUST                                     | 10       |
| GENERAL  DEVELOPMENT OF THE BUSINESS                        | 12       |
| DESCRIPTION OF  OUR BUSINESS                                | 17       |
| CAPITALIZATION  OF PWPL                                     | 18       |
| INFORMATION  RELATING TO PENN WEST                          | 19       |
| CORPORATE  GOVERNANCE                                       | 27       |
| AUDIT  COMMITTEE DISCLOSURES                                | 33       |
| DISTRIBUTIONS  TO UNITHOLDERS                               | 35       |
| MARKET FOR  SECURITIES                                      | 36       |
| INDUSTRY  CONDITIONS                                        | 39       |
| RISK FACTORS                                                | 48       |
| MATERIAL  CONTRACTS                                         | 67       |
| LEGAL  PROCEEDINGS AND REGULATORY ACTIONS                   | 67       |
| TRANSFER  AGENTS AND REGISTRARS                             | 68       |
| INTEREST OF  MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS | 68       |
| INTERESTS OF  EXPERTS                                       | 68       |
| ADDITIONAL  INFORMATION                                     | 69       |

 

**APPENDIX“A” — RESERVES DISCLOSURE**

 

AppendixA-1 — Report of Management and Directors on Reserves Data and Other Information

AppendixA-2 — Report on Reserves Data

AppendixA-3 — Statement of Reserves Data and Other Oil and Gas Information

** **

**APPENDIX“B” — MANDATE OF THE AUDIT COMMITTEE**

 

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**GLOSSARY OF TERMS**

 

The followingis a glossary of certain terms used in this Annual Information Form.

 

“**6.5% 2005 Debenture Indenture**” means thetrust indenture governing the 6.5% 2005 Debentures.

 

“**6.5% 2005 Debentures**” means the 6.5%convertible, extendible, unsecured, subordinated debentures issued on May 26,2005 pursuant to the 6.5% 2005 Debenture Indenture, which debentures wereassumed by Penn West pursuant to the Canetic Acquisition and subsequently begantrading on the TSX as securities of Penn West on January 16, 2008 underthe symbol PWT.DB.D.

 

“**6.5% 2006 Debenture Indenture**” means thetrust indenture governing the 6.5% 2006 Debentures.

 

“**6.5% 2006 Debentures**” means the 6.5%convertible, extendible, unsecured, subordinated debentures issued on August 24,2006 pursuant to the 6.5% 2006 Debenture Indenture, which debentures wereassumed by Penn West pursuant to the Canetic Acquisition and subsequently begantrading on the TSX as securities of Penn West on January 16, 2008 underthe symbol PWT.DB.F.

 

“**7.2% Debenture Indenture**” means the trustindenture governing the 7.2% Debentures.

 

“**7.2% Debentures**” means the 7.2% convertible,unsecured, subordinated debentures issued on May 2, 2006 pursuant to the7.2% Debenture Indenture, which debentures were assumed by Penn West pursuantto the Vault Acquisition and subsequently began trading on the TSX assecurities of Penn West on January 15, 2008 under the symbol PWT.DB.E.

 

“**8% 2004 Debenture Indenture**” means thetrust indenture governing the 8% 2004 Debentures.

 

“**8% 2004 Debentures**” means the 8%convertible, extendible, unsecured, subordinated debentures issued on June 15,2004 pursuant to the 8% 2004 Debenture Indenture, which debentures were assumedby Penn West pursuant to the Canetic Acquisition and subsequently began tradingon the TSX as securities of Penn West on January 16, 2008 under the symbolPWT.DB.B.

 

“**8% 2005 Debenture Indenture**” means thetrust indenture governing the 8% 2005 Debentures.

 

“**8% 2005 Debentures**” means the 8%convertible, unsecured, subordinated debentures issued on June 22, 2005pursuant to the 8% 2005 Debenture Indenture, which debentures were assumed byPenn West pursuant to the Vault Acquisition and subsequently began trading onthe TSX as securities of Penn West on January 15, 2008 under the symbolPWT.DB.C.

 

“**2007 Senior Notes**” has the meaning ascribedthereto under “General Development of the Business — History and Development —Year Ended December 31, 2007 — Private Placement of 2007 Senior Notes”.

 

“**2008 Senior Notes**” has the meaning ascribedthereto under “General Development of the Business — History and Development —Year Ended December 31, 2008 — Private Placement of 2008 Senior Notes”.

 

“**2008 Pounds Sterling Senior Notes**” has themeaning ascribed thereto under “General Development of the Business — Historyand Development — Year Ended December 31, 2008 — Private Placement of 2008Pounds Sterling Senior Notes”.

 

“**ABCA**” means the *Business Corporations Act* (Alberta), R.S.A. 2000,C. B-9, as amended, including the regulations promulgated thereunder.

 

“**Administration Agreement**” means theagreement dated May 31, 2005 between the Trustee and PWPL pursuant towhich PWPL agrees to provide certain administrative and advisory services inconnection with Penn West.

 

“**Board of Directors**” means the Board ofDirectors of PWPL.

 

“**Canadian GAAP**” means Canadian generallyaccepted accounting principles.

 

2

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“**Canetic**” means Canetic Resources Trust, atrust established under the laws of the Province of Alberta.

 

“**Canetic Acquisition**” means the plan ofarrangement under the ABCA pursuant to which Penn West acquired Canetic on January 11,2008.

 

“**CBM**” means coalbed methane.

 

“**Convertible Debentures**” means,collectively, the 6.5% 2005 Debentures, the 6.5% 2006 Debentures, the 7.2%Debentures, the 8% 2004 Debentures and the 8% 2005 Debentures.

 

“**Debenture Indentures**” means, collectively,the 6.5% 2005 Debenture Indenture, the 6.5% 2006 Debenture Indenture, the 7.2%Debenture Indenture, the 8% 2004 Debenture Indenture and the 8% 2005 DebentureIndenture.

 

“**Debenture Trustee**” means, in respect of the6.5% 2005 Debentures, Olympia Trust Company, in respect of each of the 6.5%2006 Debentures and the 8% 2004 Debentures, Computershare Trust Company ofCanada, and in respect of each of the 7.2% Debentures and the 8% 2005Debentures, Canadian Western Trust Company.

 

“**Endev**” means Endev Energy Inc., acorporation incorporated under the laws of the Province of Alberta.

 

“**Endev Acquisition**” means the plan ofarrangement under the ABCA pursuant to which Penn West acquired Endev on July 22,2008.

 

“**Engineering Reports**” means, collectively,the GLJ Report and the Sproule Report.

 

“**Form 40-F**” means our Annual Report on Form 40-Ffor the fiscal year ended December 31, 2008, filed with the SEC.

 

“**GLJ**” means GLJ Petroleum Consultants Ltd.,independent petroleum consultants of Calgary, Alberta.

 

“**GLJ Report**” means the report prepared byGLJ dated February 24, 2009evaluating approximately 60% ofthe crude oil, natural gas and natural gas liquids reserves and the net presentvalue of future net revenue attributable to those reserves effective as at December 31,2008.

 

“**Gross**” means:

 

(a)                                  in relation to our interest in production or reserves, our workinginterest (operating or non-operating) share before deduction of royalties andwithout including any royalty interests of ours;

 

(b)                                 in relation to wells, the total number of wells in which we have aninterest; and

 

(c)                                  in relation to properties, the total area of properties in which wehave an interest.

 

“**Internal Notes**” means the unsecuredsubordinated promissory notes issued by PWPL and certain other OperatingEntities to Penn West.

 

“**Net**” means:

 

(a)                                  in relation to our interest in production or reserves, our workinginterest (operating or non-operating) share after deduction of royaltyobligations, plus our royalty interests in production or reserves;

 

(b)                                 in relation to our interest in wells, the number of wells obtainedby aggregating our working interest in each of our gross wells; and

 

(c)                                  in relation to our interest in a property, the total area in whichwe have an interest multiplied by the working interest we owned.

 

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“**NI 51-101**” means National Instrument 51-101— Standards of Disclosure for Oil and Gas Activities.

 

“**Non-Resident**” means: (i) a person whois not a resident of Canada for the purposes of the Tax Act; or (ii) apartnership that is not a Canadian partnership for the purposes of the Tax Act.

 

“**NPI Agreements**” means the net profitsinterest agreements between Penn West and certain of Penn West’s OperatingEntities.

 

“**NPIs**” means the net profits interestsgranted to Penn West under the NPI Agreements.

 

“**NYSE**” means the New York Stock Exchange.

 

“**Operating Entities**” means, collectively,PWPL, Penn West Partnership, Canetic ABC Limited Partnership, Titan CanadaResources, Canetic Resources Partnership, Petrofund Ventures Trust and UptonResources Inc., each a direct or indirect wholly-owned subsidiary of Penn Westas at the date hereof, and “**OperatingSubsidiary**” means any one of them, as applicable.

 

“**Operating Entities Securities**” means theInternal Notes, the NPIs, the common shares of PWPL and any other securities ofthe Operating Entities owned, directly or indirectly, by Penn West.

 

“**Penn West**”, “**we**”, “**us**”**,**“**our**”or****“**Trust**”****means PennWest Energy Trust, a trust established under the laws of the Province ofAlberta pursuant to the Trust Indenture. Where the context requires, these terms also include all of Penn West’sSubsidiaries on a consolidated basis.

 

“**Penn West Partnership**”****means Penn West Petroleum, a generalpartnership, the partners of which as at the date hereof are PWPL, TrocanaResources Inc. and Canetic Saskatchewan Trust.

 

“**Petrofund**” means Petrofund Energy Trust, atrust established under the laws of the Province of Ontario.

 

“**Petrofund Acquisition**” means the plan ofarrangement under the ABCA pursuant to which Penn West acquired Petrofund on June 30,2006.

 

“**PWPL**” means Penn West Petroleum Ltd., acorporation amalgamated under the ABCA, a wholly-owned subsidiary of Penn Westand the administrator of Penn West pursuant to the Administration Agreement.

 

“**SEC**” means the United States Securities and ExchangeCommission.

 

“**Sproule**” means Sproule Associates Limited,independent petroleum consultants of Calgary, Alberta.

 

“**Sproule Report**” means the report preparedby Sproule dated February 26,2009 evaluating approximately 32%and auditing approximately 8% ofthe crude oil, natural gas and natural gas liquids reserves and the net presentvalue of future net revenue attributable to those reserves effective as at December 31,2008.

 

“**Subsidiaries**” has the meaning ascribedthereto in the *Securities Act*(Ontario) and, for greater certainty, includes all corporations, partnershipsand trusts owned, controlled or directed, directly or indirectly, by Penn West.

 

“**Tax Act**” means the *Income Tax Act*(Canada), R.S.C. 1985, C. 1(5th Supp.), as amended, including the regulations promulgated thereunder, asamended from time to time.

 

“**Trust Indenture**” meansthe trust indenture between the Trustee and PWPL, as amended and restated as ofJune 30, 2006 and as subsequently amended on November 29, 2007.

 

“**Trust Unit**” means atrust unit issued by us, each trust unit representing an equal undividedbeneficial interest in our assets.

 

“**Trustee**” meansCIBC Mellon Trust Company, our trustee.

 

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“**TSX**” means the Toronto Stock Exchange.

 

“**United States**” or “**U.S.**” means the United States of America.

 

“**Unitholders**” means holders of Penn WestTrust Units.

 

“**undeveloped land**” and “**unproved property**” each mean a property orpart of a property to which no reserves have been specifically attributed.

 

“**U.S. GAAP**” means United States generallyaccepted accounting principles.

 

“**Vault**” means Vault Energy Trust, a trustestablished under the laws of the Province of Alberta.

 

“**Vault Acquisition**” means the plan ofarrangement under the ABCA pursuant to which Penn West acquired Vault on January 10,2008.

 

**CONVENTIONS**

** **

Certain termsused herein are defined in the “Glossary of Terms”.  Certain other terms used herein but not definedherein are defined in NI 51-101 and, unless the context otherwiserequires, shall have the same meanings herein as in NI 51-101.  A discussion of the principal differencesbetween Penn West’s financial results calculated under Canadian GAAP and underU.S. GAAP is included in the Form 40-F. On March 26, 2009, the exchange rate for U.S. dollars, expressed inCanadian dollars, based on the noon rate as reported by the Bank of Canada, wasCdn$1.00 equals US$0.8110.

 

All dollar amounts in this document are expressed in Canadian dollars,except where otherwise indicated. References to “**$**” or “**Cdn$**” areto Canadian dollars, references to “**US$**”are to United States dollars and references to “**£**” are to pounds sterling.

 

All financialinformation herein has been presented in Canadian dollars in accordance withCanadian GAAP, which differs from U.S. GAAP.

 

**ABBREVIATIONS**

** **
| **Oil  and Natural Gas Liquids** |
|----------------------------------|
|                             |   |
| bbl                              | barrel or  barrels |
| bbl/d                            | barrels per  day |
| Mbbl                             | thousand  barrels |
| MMbbl                            | million  barrels |
| NGLs                             | natural gas  liquids |
| MMboe                            | million  barrels of oil equivalent |
| Mboe                             | thousand  barrels of oil equivalent |
| boe/d                            | barrels of  oil equivalent per day |
|                             |   |
| **Natural Gas**                  |   |
|                             |   |
| GJ                               | gigajoule |
| Gj/d                             | gigajoules  per day |
| Mcf                              | thousand  cubic feet |
| MMcf                             | million  cubic feet |
| Bcf                              | billion  cubic feet |
| Mcf/d                            | thousand  cubic feet per day |
| MMcf/d                           | million  cubic feet per day |
| m3                               | cubic metres |
| MMbtu                            | million  British Thermal Units |

 

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**Other**

 
| BOE or boe | means barrel  of oil equivalent, using the conversion factor of 6 Mcf of natural gas being  equivalent to one barrel of oil. Boes may be misleading, particularly if used  in isolation. A boe conversion ratio of 6 Mcf: 1 bbl is based on an energy  equivalency conversion method primarily applicable at the burner tip and does  not represent a value equivalency at the wellhead. |
|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|       |                                                                                                                                                                                                                                                                                                                                                                                     |
| WTI        | means West  Texas Intermediate, the reference price paid in United States dollars at  Cushing, Oklahoma for crude oil of standard grade.                                                                                                                                                                                                                                                 |
|       |                                                                                                                                                                                                                                                                                                                                                                                     |
| API        | means  American Petroleum Institute.                                                                                                                                                                                                                                                                                                                                                     |
|       |                                                                                                                                                                                                                                                                                                                                                                                     |
| °API  | means the  measure of the density or gravity of liquid petroleum products derived from a  specific gravity.                                                                                                                                                                                                                                                                              |
|       |                                                                                                                                                                                                                                                                                                                                                                                     |
| psi        | means pounds  per square inch.                                                                                                                                                                                                                                                                                                                                                           |
|       |                                                                                                                                                                                                                                                                                                                                                                                     |
| MM$        | means one  million dollars.                                                                                                                                                                                                                                                                                                                                                              |
|       |                                                                                                                                                                                                                                                                                                                                                                                     |
| MW         | means  megawatt.                                                                                                                                                                                                                                                                                                                                                                         |
|       |                                                                                                                                                                                                                                                                                                                                                                                     |
| MWh        | means  megawatt hour.                                                                                                                                                                                                                                                                                                                                                                    |
|       |                                                                                                                                                                                                                                                                                                                                                                                     |
| CO2        | means carbon  dioxide.                                                                                                                                                                                                                                                                                                                                                                   |

 

**OIL AND GAS INFORMATION ADVISORIES**

 

**Whereany disclosure of reserves data is made in this Annual InformationForm (including the Appendices hereto) that does not reflect all of thereserves of Penn West, the reader should note that the estimates of reservesand future net revenue for individual properties may not reflect the sameconfidence level as estimates of reserves and future net revenue for allproperties, due to the effects of aggregation.**

 

All productionand reserves quantities included in this Annual Information Form (includingthe Appendices hereto) have been prepared in accordance with Canadian practicesand specifically in accordance with NI 51-101.  These practices are different from thepractices used to report production and to estimate reserves in reports andother materials filed with the SEC by companies in the United States.  See “Risk Factors - Canadian and UnitedStates practices differ in reporting reserves and production and our estimatesmay not be comparable to those of companies in the United States” for a summaryof such differences.  Nevertheless, aspart of the Form 40-F, Penn West has disclosed proved reserves quantitiesusing the standards contained in SEC Regulation S-X, and the standardizedmeasure of discounted future net cash flows relating to proved oil and gasreserves determined in accordance with Statement No. 69 of the U.S.Financial Accounting Standards Board, “Disclosures About Oil and Gas ProducingActivities”, which disclosure complies with the SEC’s rules for disclosingoil and gas reserves.

 

**Referencesin this Annual Information Form to undeveloped land and unprovedproperties held, owned or acquired by us, or in respect of which we have aninterest, refer to undeveloped land or unproved properties in respect of whichwe have a lease or other contractual right to explore for, develop and exploithydrocarbons underlying such undeveloped land or unproved properties.**

 

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**CONVERSIONS**

** **

The followingtable sets forth certain conversions between Standard Imperial Units and theInternational System of Units (or metric units).

 

| **To Convert From**       | ** ** | **To**       | ** ** | **Multiply By** | ** ** |
|---------------------------|------------|--------------|------------|-----------------|------------|
|                      |       |         |       |            |       |
| Mcf                       |       | cubic metres |       | 28.174          |       |
| cubic metres              |       | cubic feet   |       | 35.494          |       |
| bbl                       |       | cubic metres |       | 0.159           |       |
| cubic metres              |       | bbl          |       | 6.293           |       |
| feet                      |       | metres       |       | 0.305           |       |
| metres                    |       | feet         |       | 3.281           |       |
| miles                     |       | kilometres   |       | 1.609           |       |
| kilometres                |       | miles        |       | 0.621           |       |
| acres                     |       | hectares     |       | 0.405           |       |
| hectares                  |       | acres        |       | 2.500           |       |
| gigajoules  (at standard) |       | MMbtu        |       | 0.950           |       |
| MMbtu (at  standard)      |       | gigajoules   |       | 1.053           |       |
| gigajoules  (at standard) |       | Mcf          |       | 1.055           |       |

 

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** **

**SPECIAL NOTE REGARDING FORWARD-LOOKINGSTATEMENTS**

** **

In theinterest of providing Unitholders and potential investors with informationregarding Penn West, including management’s assessment of Penn West’s futureplans and operations, certain statements contained and incorporated byreference in this document constitute forward-looking statements or information(collectively “**forward-looking statements**”)within the meaning of the “safe harbour” provisions of applicable securitieslegislation.  Forward-looking statementsare typically identified by words such as “anticipate”, “continue”, “estimate”,“expect”, “forecast”, “may”, “will”, “project”, “could”, “plan”, “intend”,“should”, “believe”, “outlook”, “potential”, “target” and similar wordssuggesting future events or future performance. In addition, statements relating to “reserves” or “resources” are deemedto be forward-looking statements as they involve the implied assessment, basedon certain estimates and assumptions, that the reserves and resources describedexist in the quantities predicted or estimated and can be profitably producedin the future.  In particular, thisdocument and the documents incorporated by reference herein contain, withoutlimitation, forward-looking statements pertaining to the following: theperformance characteristics of our oil and natural gas properties; thepotential impact on our business, business strategies and plans, businessmodel, future growth prospects, distribution policies and Unitholders of theSIFT Tax (as defined herein) and the different actions that we might take inresponse to the SIFT Tax and the potential impact those actions could have onus and our Unitholders, including without limitation, our potential ability toshield our taxable income from income tax using our tax pools for a period oftime following the implementation of the SIFT Tax and the impact this wouldhave on our distributions and Unitholders; the impact that the new Albertaroyalty framework may have on us, including on our business strategies andplans; our environmental regulation compliance costs and strategies, thesufficiency of our environmental program and our ability to fund our assetretirement obligations; oil and natural gas production level estimates;our 2009 capital expenditure levels, the timing ofmaking said expenditures, the key elements of our 2009 capital expenditureprogram and the method of funding said expenditures; our business strategies; our exploration anddevelopment plans for our oil and natural gas properties in 2009 and beyond; matters relating to the proposed acquisition of Reece EnergyExploration Corp., including the acquisition metrics, the anticipated benefitsof the acquisition and the anticipated impact of the acquisition on our 2009capital program; funding sources for distributions and distribution levels; the quantity andrecoverability of our oil and natural gas reserves and resources; currencyexchange rates, inflation rates and interest rates; thenature and effectiveness of our risk management strategies; our outlook for oiland natural gas prices; and our intention and abilityto maintain a balanced portfolio of liquids and natural gas production and thebenefits we may derive therefrom.

 

With respectto forward-looking statements contained or incorporated by reference****in this document, we have made assumptionsregarding, among other things: futurecapital expenditure levels; future oil and natural gas prices and differentialsbetween light, medium and heavy oil prices; future oil and natural gasproduction levels; future exchange rates and interest rates; the amount offuture cash distributions that we intend to pay; the cost of expanding ourproperty holdings; our ability to obtain equipment in a timely manner to carryout development activities; our ability to market our oil and natural gassuccessfully to current and new customers; the impact of increasingcompetition; our ability to obtain financing on acceptable terms; and ourability to add production and reserves through our development and exploitationactivities.  In addition, many of theforward-looking statements contained in this document are located proximate toassumptions that are specific to those forward-looking statements, and suchassumptions should be taken into account when reading such forward-lookingstatements.

 

Although PennWest believes that the expectations reflected in the forward-looking statementscontained or incorporated by reference in this document, and the assumptions onwhich such forward-looking statements are made, are reasonable, there can be noassurance that such expectations will prove to be correct.  Readers are cautioned not to place unduereliance on forward-looking statements included or incorporated by reference inthis document, as there can be no assurance that the plans, intentions orexpectations upon which the forward-looking statements are based will occur. Bytheir nature, forward-looking statements involve numerous assumptions, knownand unknown risks and uncertainties that contribute to the possibility that thepredictions, forecasts, projections and other forward-looking statements willnot occur, which may cause Penn West’s actual performance and financial resultsin future periods to differ materially from any estimates or projections offuture performance or results expressed or implied by such forward-lookingstatements.  These risks anduncertainties include, among other things: the impact of weather conditions on seasonal demand and our ability toexecute capital programs; risks inherent in oil and natural gas operations;uncertainties associated with estimating reserves and resources; competitionfor, among other things, capital, acquisitions of reserves, resources, undevelopedlands and skilled personnel; incorrect assessments of the value ofacquisitions; geological, technical, drilling and processing problems; generaleconomic conditions in Canada, the U.S. and globally, and in particular, theongoing global financial crisis and its impacts on commodity prices and ouraccess to capital; industry conditions, including fluctuations in the price ofoil and natural gas; 

 

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royaltiespayable in respect of our oil and natural gas production and changes thereto;changes in government regulation of the oil and natural gas industry, includingenvironmental regulation; fluctuations in foreign exchange or interest rates;unanticipated operating events that can reduce production or cause productionto be shut-in or delayed; failure to obtain industry partner and otherthird-party consents and approvals when required; stock market volatility andmarket valuations; OPEC’s ability to control production and balance globalsupply and demand of crude oil at desired price levels; political uncertainty,including the risks of hostilities, in the petroleum producing regions of theworld; the need to obtain required approvals from regulatory authorities fromtime to time; failure to realize the anticipated benefits of acquisitions,including the completed and proposed acquisitions discussed herein; changes intaxation laws and regulations that affect us and our securityholders; changesin the Alberta royalty framework and their impact on us; uncertainty ofobtaining required approvals in respect of acquisitions and mergers; and theother factors described under “Risk Factors” in this document and in PennWest’s public filings available in Canada at www.sedar.com and in the UnitedStates at www.sec.gov.  Readers arecautioned that this list of risk factors should not be construed as exhaustive.

 

Theforward-looking statements contained and incorporated by reference in thisdocument speak only as of the date of this document. Except as expresslyrequired by applicable securities laws, Penn West does not undertake anyobligation to publicly update or revise any forward-looking statements, whetheras a result of new information, future events or otherwise. The forward-lookingstatements contained and incorporated by reference in this document areexpressly qualified by this cautionary statement.

** **

**NON-GAAP MEASURES**

** **

This AnnualInformation Form includes measures not defined under generally acceptedaccounting principles (“GAAP”), including funds flow and netback.  Non-GAAP measures do not have anystandardized meaning prescribed by GAAP and are therefore unlikely to becomparable to similar measures presented by other issuers. Funds flow is cashflow from operating activities before changes in non-cash working capital andasset retirement expenditures. Funds flow is used to assess our ability to funddistributions and planned capital programs. Netback is a per-unit-of-productionmeasure of operating margin used in capital allocation decisions.For moreinformation, see Penn West’s management’s discussion and analysis for the yearended December 31, 2008 (available on SEDAR at www.sedar.com and on EDGARat www.sec.gov), which includes a reconciliation of “funds flow” to cash flowfrom operating activities and sets out the method that we use to calculate ournetbacks.

** **

**EFFECTIVE DATE OF INFORMATION**

** **

**Exceptwhere otherwise indicated, the information in this Annual InformationForm is presented as at the end of Penn West’s most recently completedfinancial year, being December 31, 2008.**

 

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**PENN WEST ENERGY TRUST**

** **

**General**

** **

We are an open-end investment trust createdon April 22, 2005 under the laws of the Province of Alberta pursuant tothe Trust Indenture.  CIBC Mellon TrustCompany is our Trustee.  Thebeneficiaries of Penn West are the holders of the Trust Units.  Our principal and head office is located at Suite 200,207 – 9th Avenue S.W., Calgary, Alberta, T2P 1K3.

 

We commenced operations in our currentstructure on June 1, 2005 after the completion of a plan of arrangementunder the ABCA.  Pursuant to this plan ofarrangement, holders of common shares of PWPL received three Trust Units foreach one of their common shares.

 

**Inter-Corporate Relationships**

** **

The following are the names, the percentageof votes attaching to all voting securities beneficially owned, or controlledor directed, directly or indirectly, by Penn West, and the jurisdiction ofincorporation, continuance, formation or organization of our direct andindirect material Subsidiaries.

 
| ** **               | ** ** | **Percentage of Votes** | ** ** | **Nature of Entity** | ** ** | **Jurisdiction of   Incorporation/**** ****Formation** | ** ** |
|--------------------------|------------|-----------------------------------|------------|--------------------------------|------------|-----------------------------------------------------------------------|------------|
| Penn West Petroleum Ltd. |       | 100                               | %          | Corporation                    |       | Alberta                                                               |       |
| Penn West Petroleum      |       | 100                               | %          | General Partnership            |       | Alberta                                                               |       |

** **

**Our Organizational Structure**

** **

The following diagram sets forth thesimplified organizational structure of Penn West.

 

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Notes:

 

(1)           The Unitholders own 100 percent of Penn West’s equity.

(2)           Cash distributions are made on a monthly basis toUnitholders based upon, among other things, our funds flow.  Our primary sources of funds flow arepayments from PWPL and our other Operating Entities pursuant to the NPIs andinterest on the principal amount of the Internal Notes.

(3)           PWPL was formed effective as of January 1, 2009 pursuant to theamalgamation of Penn West Petroleum Ltd., Endev Energy Inc., 990009Alberta Inc., 1075264 Alberta Ltd. and 1167639 Alberta Ltd.

(4)           As at the date hereof, PWPL, Trocana Resources Inc. and****CaneticSaskatchewan Trust****are thepartners of Penn West Partnership.

(5)           The other Operating Entities are direct or indirectwholly-owned subsidiaries of Penn West. As at December 31, 2008, other than PWPL and the Penn WestPartnership, Penn West does not have any subsidiaries: (i) the totalassets of which exceed 10% of Penn West’s consolidated assets (or 20% of PennWest’s consolidated assets when aggregated with all other subsidiaries of PennWest other than PWPL and the Penn West Partnership); or (ii) the sales andoperating revenues of which exceed 10% of Penn West’s consolidated sales andoperating revenues (or 20% of Penn West’s consolidated sales and operatingrevenues when aggregated with all other subsidiaries of Penn West other thanPWPL and the Penn West Partnership).

 

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**GENERAL DEVELOPMENT OF THE BUSINESS**

** **

**History and Development**

** **

***YearEnded December 31, 2006***

*** ***

*NYSE Listing*

* *

On June 22, 2006, the Trust Units werelisted on the NYSE.

 

*Petrofund Acquisition*

* *

Effective June 30, 2006, Penn Westcompleted the Petrofund Acquisition, pursuant to which Penn West acquiredPetrofund on the basis of an exchange of 0.60 of a Trust Unit for each one (1) trustunit of Petrofund.  An aggregate ofapproximately 70.7 million Trust Units were issued.  A special cash distribution in the amount of$1.10 per trust unit of Petrofund, of which $0.10 per unit was to align thedistribution record dates of the trusts, was made immediately prior to thecompletion of the Petrofund Acquisition to the holders of trust units ofPetrofund.  An aggregate of $130million was distributed.  As a result ofthe Petrofund Acquisition, Penn West acquired 71 MMbbl of light/mediumcrude oil and NGLs, 1 MMbbl of heavy oil and 279 Bcf of natural gas on aproved reserve basis, 94 MMbbl of light/medium crude oil and NGLs,1 MMbbl of heavy oil and 371 Bcf of natural gas on a proved plus probablereserve basis, and 352,600 net acres of undeveloped land.  Penn West also assumed $610 million ofbank indebtedness of Petrofund in connection with the Petrofund Acquisition.

 

*Other Acquisitions and Dispositions*

* *

We completedproperty acquisitions, net of dispositions, of $6 million in 2006.  Other than the Petrofund Acquisitiondescribed above, we did not complete any corporate acquisitions in 2006.

 

*Changes to Taxation of Income Trusts*

 

On October 31, 2006, the FederalMinister of Finance proposed to deny the deduction of distributions at thetrust level and subject any income of certain publicly traded mutual fundtrusts to tax at rates comparable to the combined federal and provincialcorporate tax and to treat such distributions as taxable dividends to theunitholders (the “**SIFT Tax**”).  On December 21, 2006, the FederalMinister of Finance released draft legislation to implement the SIFT Taxpursuant to which, commencing January 1, 2011 (provided we only experience“normal growth” and no “undue expansion” before then) certain distributionsfrom us which would have otherwise been taxed as ordinary income generally willbe characterized as dividends to our Unitholders and will be subject to tax atthe corporate rates at the trust level. On June 22, 2007, the legislation received Royal assent.

 

TheTrust is a taxable entity under the Tax Act and is taxable only on income thatis not distributed or distributable to the Unitholders.  As the Trust distributes all of its taxableincome to the Unitholders pursuant to the Trust Indenture and currentlysatisfies the requirements of the Tax Act applicable to the Trust, the Trustdoes not expect to pay income taxes until the earlier of January 1, 2011or if and when it ceases to be a trust. The SIFT Tax will not impose a tax on distributions from entities, suchas the Trust, until January 1, 2011 as long as the Trust experiences only “normalgrowth” as set out in the guidelines described below.  Commencing in January 2011, the Trustwill be liable for tax on all distributions of income paid orpayable to Unitholders, which distributions the Trust will no longer be able todeduct in computing its taxable income. The Trust currently has significant tax pools and expects to continue toincrease its tax pool base until 2011. Accordingly, it is expected that the Trust will be able to shelterincome for a period of time after the application of the SIFT Tax.

 

The SIFT Tax provides that, while there is nointention to prevent “normal growth” during the transitional period, any “undueexpansion” would result in the transition period being terminated with the lossof the benefit to us of that transitional period.  As a result, the adverse tax consequencesresulting from the SIFT Tax could be borne sooner than January 1,2011.  On December 15, 2006, theDepartment of Finance issued guidelines with respect to what is meant by “normalgrowth” in this context.  Specifically,the Department of Finance stated that “normal growth” would include equitygrowth within certain “safe harbour” limits, measured by reference to aspecified investment flow-through’s (a “**SIFT**”)market capitalization as of the end of trading on October 31, 2006 (whichwould include only the market value of the SIFT’s issued and outstanding

 

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publicly-traded trust units, and not anyconvertible debt, options or other interests convertible into or exchangeablefor trust units).  Those safe harbour limits were 40% for theperiod from November 1, 2006 to December 31, 2007, and 20% each forcalendar year 2008, 2009 and 2010. Moreover, these limits were cumulative, so that any unused limit for aperiod carries over into the subsequent period.  Additional details of the Department ofFinance’s guidelines include the following: (i) new equity for thesepurposes includes units and debt that is convertible into units (and mayinclude other substitutes for equity if attempts are made to develop those);and (ii) replacing debt that was outstanding as of October 31, 2006with new equity, whether by a conversion into trust units of convertibledebentures or otherwise, will not be considered growth for these purposes andwill therefore not affect the safe harbour.

 

On December 4, 2008, the FederalMinister of Finance announced changes to the guidelines discussed above toallow a SIFT to accelerate the utilization of the SIFT annual safe harbouramount for each of 2009 and 2010 so that the safe harbour amounts for 2009 and2010 are available on and after December 4, 2008.  This change does not alter the maximumpermitted expansion threshold for a SIFT, but it allows a SIFT to use itsnormal growth room remaining as of December 4, 2008 in a single year,rather than staging a portion of the normal growth room over the 2009 and 2010years.  The Department of Finance hasindicated that the issuance of trust units by a SIFT as consideration inconnection with the acquisition of, or the merger with, another SIFT, will notbe considered growth for these purposes and will therefore not affect a SIFT’ssafe harbour.  Therefore, our issuance ofTrust Units in connection with the acquisition of Canetic and Vault is notconsidered growth for these purposes and did not affect our safe harbour.  The Department of Finance has also indicatedthat a SIFT’s market capitalization for the purpose of calculating a SIFT’s “safeharbour” equity growth limit is equal to the aggregate market capitalization ofthe SIFT and all SIFTs acquired by such SIFT as of the end of trading on October 31,2006.  The combined market capitalizationof the Trust, Canetic and Vault as of the close of trading on October 31,2006, having regard only to the issued and outstanding publicly-traded TrustUnits and Canetic and Vault trust units at such date, was approximately $15billion.  We believe that, as at March 26, 2009, our remaining combined “safeharbour” equity growth amount for the period ending December 31, 2010 isapproximately $14****billion (not including equity,including convertible debentures, issued to replace debt that was outstandingon October 31, 2006).

 

Currently, the SIFT Tax rules providethat the SIFT Tax rate will be the federal general corporate income tax rate(which is anticipated to be 16.5% in 2011 and 15% in 2012) plus the provincialSIFT tax rate discussed below.  Pursuant to proposed regulations to the TaxAct, the provincial SIFT Tax rate will be based on the general provincialcorporate income tax rate in each province in which the Trust has a permanentestablishment.  For purposes ofcalculating this component of the tax, the general corporate taxable provincialallocation formula will be used. Specifically, the Trust’s taxable distributions, if any, will beallocated to provinces by taking half of the aggregate of: (i) thatproportion of the Trust’s taxable distributions, if any, for the year that theTrust’s wages and salaries in the province are of its total wages and salariesin Canada; and (ii) that proportion of the Trust’s taxable distributions,if any, for the year that the Trust’s gross revenues in the province are of itstotal gross revenues in Canada.  It isanticipated that the Trust would be considered to have a permanentestablishment in Alberta only, where the provincial tax rate in 2011 isexpected to be 10%, which will result in an effective tax rate of 26.5% in2011.  Taxable distributions, if any,that are not allocated to any province, would instead be subject to a 10% rateconstituting the provincial component.

 

On July 14, 2008, the Federal Minister of Finance announcedproposed amendments to the Tax Act, including technical amendments to clarifycertain aspects of the SIFT Tax and to provide rules to facilitate theconversion of existing SIFTs into corporations on a tax-deferred basis (the “**Conversion Rules**”).  The Conversion Rules address many of theprincipal substantive and administrative issues that arise when structuring acorporate conversion of an income trust under the Tax Act. The Conversion Rules contemplatetwo alternatives for the conversion of a publicly-traded SIFT into a taxableCanadian corporation and the winding-up of the SIFT’s underlyingstructure.  The first alternativeinvolves the winding-up of the SIFTinto a taxable Canadian corporationwhereas the second approach involves the distribution by the publicly-tradedSIFT of shares of an underlying taxable Canadian corporation to itsunitholders.  The Conversion Rules willgenerally only apply to the winding-up of a SIFT or a distribution of sharescompleted after July 14, 2008 and before 2013.  Bill C-10, which received Royal Assent on March 12,2009, contained legislation implementing the Conversion Rules.

 

***As a result ofthe enactment of the SIFT Tax in 2007, the future income taxes disclosed in ourfinancial statements were adjusted to include temporary differences between theaccounting and tax bases of our assets and liabilities at the trust level, asfurther described in Note***9 to our audited consolidatedfinancial statements for the year ended December 31, 2008. In addition,the reported estimated net present value of future net revenues from our oiland natural gas reserves on an “after-tax” basis now reflects the impact of theSIFT Tax. We continue to evaluate alternatives to determine the optimalstructure for our Unitholders beyond 2010. We are currently hesitant to make structural changes prior to the end of2010 unless

 

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***opportunitiesarise, as we believe the exemption period has value for our Unitholders. Unlesscircumstances change within the current capital markets or the regulatory, taxor political environment, we currently believe that we will most likely convertinto a dividend paying corporation. However, we are keeping our options open atthis time and cannot provide any assurances in this regard. We do not expectthat a conversion to a corporation would have a major impact on our underlyingoperating strategy or business affairs, but cannot provide any assurances in thisregard. We expect that such a conversion could be achieved without creating ataxable event for most of our Unitholders, particularly if a conversion werecompleted prior to January 1, 2013. However, going forward, the tax treatment of our distributions ordividends might be different for our Unitholders or shareholders, as the casemay be, depending on the Unitholder’s tax jurisdiction and whether theUnitholder holds its investment in a taxable account or tax-deferredaccount. ***Foradditional information on the SIFT Tax, including its potential impact on usand our Unitholders and the actions that we might take in response to the SIFTTax (including with respect to our anticipated tax horizon), see thefollowing:  “Risk Factors” in this AnnualInformation Form; “Other Oil and Gas Information – Tax Horizon” in Appendix A-3to this Annual Information Form; and “Enactment of the Tax on Income Trusts”set forth in our management’s discussion and analysis for the year ended December 31,2008 (available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov), whichdisclosure is incorporated herein by reference.

*** ***

***YearEnded December 31, 2007***

*** ***

*April 2007 Asset Acquisition*

* *

On April 11,2007, Penn West completed the acquisition (the “**April 2007 Asset Acquisition**”) of certain conventionaloil and natural gas assets located primarily in the Province of Alberta, forcash consideration of approximately $329 million.  As a result of the acquisition, Penn Westacquired 6 MMbbl of light/medium crude oil and NGLs, 0.1 MMbbl of heavy oil and16 Bcf of natural gas on a proved reserve basis, 8 MMbbl of light/medium crudeoil and NGLs, 0.1 MMbbl of heavy oil and 22 Bcf of natural gas on a proved plusprobable reserve basis, and 190,000 net acres of undeveloped land.  The acquisition was financed using Penn West’sexisting syndicated credit facility and a new $250 million unsecured, demandcredit facility.

 

*Other Acquisitions and Dispositions*

* *

In addition tothe April 2007 Asset Acquisition described above, we completed propertyacquisitions, net of dispositions, of $93 million in 2007.  We also completed one corporate acquisitionfor total cash consideration of $21 million resulting in total acquisitions,net of dispositions, of $443 million in 2007 (including the April 2007 AssetAcquisition).

 

*Private Placement of 2007 Senior Notes*

* *

Effective May 31,2007, PWPL completed the private placement of an aggregate of US$475 millionprincipal amount of notes (the “**2007 SeniorNotes**”).  The privateplacement consisted of the issuance of US$160 million principal amount of 5.68percent notes due in 2015, US$155 million principal amount of 5.80 percentnotes due in 2017, US$140 million principal amount of 5.90 percent notes due in2019 and US$20 million principal amount of 6.05 percent notes due in 2022.  The 2007 Senior Notes are unsecured and rankequally with Penn West’s bank credit facilities.  The proceeds of the 2007 Senior Notes wereused to repay a portion of the indebtedness under Penn West’s bank creditfacilities.

 

***YearEnded December 31, 2008***

*** ***

*Vault Acquisition*

* *

Effective January 10,2008, Penn West completed the Vault Acquisition, pursuant to which Penn Westacquired Vault on the basis of an exchange of 0.14 of a Trust Unit for each onetrust unit of Vault, 0.14 of a Trust Unit for each one trust unit of Vault intowhich the Series A exchangeable shares of Vault Energy Inc. wereexchangeable, and a payment of $0.51 for each one warrant to purchase a trustunit of Vault.  An aggregate ofapproximately 5.6 million Trust Units were issued and an aggregate ofapproximately $768,111 was paid.  As aresult of the Vault Acquisition, Penn West acquired 7 MMbbl of light/mediumcrude oil and NGLs and 56 Bcf of natural gas on a proved reserve basis, and 10MMbbl of light/medium crude oil and NGLs and 74 Bcf of natural gas on a provedplus probable reserve basis.  Penn Westalso acquired 125,000 net acres of undeveloped land.

 

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In connectionwith the Vault Acquisition, Penn West also assumed approximately $89 million ofbank indebtedness of Vault, $50 million principal amount of 7.2% Debenturesissued by Vault and $49 million principal amount of 8% 2005 Debentures issuedby Vault.  On March 5, 2008, PennWest repurchased for cancellation $24 million principal amount of the 7.2%Debentures and $11,000 principal amount of the 8% 2005 Debentures pursuant toissuer bids required by the 7.2% Debenture Indenture and the 8% 2005 DebentureIndenture, respectively.

 

*Canetic Acquisition*

* *

Effective January 11,2008, Penn West completed the Canetic Acquisition, pursuant to which Penn Westacquired Canetic on the basis of an exchange of 0.515 of a Trust Unit for eachone trust unit of Canetic.  An aggregateof approximately 124.3 million Trust Units were issued.  In addition, a special cash distribution inthe amount of $0.09 per trust unit of Canetic was made to holders of trustunits of Canetic of record at the close of business on January 10,2008.  An aggregate of approximately $22million was distributed to Canetic unitholders on January 15, 2008.  As a result of the Canetic Acquisition, PennWest acquired approximately 89 MMbbl of light/medium crude oil and NGLs, 13MMbbl of heavy oil and 408 Bcf of natural gas on a proved reserve basis and 120MMbbl of light/medium crude oil and NGLs, 17 MMbbl of heavy oil and 564 Bcf ofnatural gas on a proved plus probable reserve basis.  Penn West also acquired 774,000 net acres ofundeveloped land.

 

In connectionwith the Canetic Acquisition, Penn West assumed approximately $1.4 billion ofbank indebtedness of Canetic, $18 million principal amount of 6.5% 2005Debentures issued by Canetic, $229 million principal amount of 6.5% 2006Debentures issued by Canetic, $8 million principal amount of 8% 2004 Debenturesissued by Canetic and $6 million principal amount of 9.4% convertible unsecuredsubordinated debentures issued by Canetic (which were subsequently repaid on July 31,2008 when they matured and are no longer outstanding).

 

Concurrentwith the closing of the Canetic Acquisition, Penn West secured a $4 billioncredit facility for a three-year term with a syndicate of 18 Canadian andinternational banks.  The new creditfacility was initially used to retire Penn West’s indebtedness under its thenexisting bank credit facilities and to retire all bank indebtedness assumed byPenn West in connection with the Vault Acquisition and the Canetic Acquisition.

 

*Endev Acquisition*

 

Effective July 22,2008, Penn West completed the Endev Acquisition, pursuant to which Penn West acquiredEndev on the basis of an exchange of 0.041 of a Trust Unitfor each one (1) common share of Endev. An aggregate of approximately 3.6 million Trust Units were issued.  As a result of the Endev Acquisition, PennWest acquired approximately 1,242 Mbblof light/medium crude oil and NGLs, 56 Mbblof heavy oil and 28,021 MMcf ofnatural gas on a proved reserve basis, 1,900 Mbblof light/medium crude oil and NGLs, 81 Mbbl of heavy oil and 40,760 MMcf of natural gas on a provedplus probable reserve basis, and 98,580net acres of undeveloped land.  Penn Westalso assumed $45 million ofdebt and working capital in connection with the Endev Acquisition.

 

*Other Acquisitions and Dispositions*

* *

We completedproperty dispositions, net of acquisitions, of $50****million in 2008.

* *

*Private Placement of 2008 Senior Notes*

* *

Effective May 29, 2008, PWPL completed the private placement of anaggregate of US$480 million and Cdn$30 million principal amount of seniorguaranteed unsecured notes (the “**2008 SeniorNotes**”). The private placement consisted of the issuance of US$153million principal amount of 6.12 percent notes due in 2016, US$278 millionprincipal amount of 6.30 percent notes due in 2018, Cdn$30 million principalamount of 6.16 percent notes due in 2018 and US$49 million principal amount of6.40 percent notes due in 2020. The 2008 Senior Notes are unsecured and rankequally with PWPL’s bank credit facilities and the 2007 Senior Notes. The proceeds of theprivate placement of the 2008 Senior Notes were used to repay a portion of theindebtedness outstanding under our bank creditfacilities.

 

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*Private Placement of 2008 Pounds SterlingSenior Notes*

* *

Effective July 31, 2008, PWPL completed the private placement ofan aggregate of £57 million principal amount of senior guaranteed unsecurednotes (the “**2008 Pounds Sterling Senior Notes**”).The private placement consisted of the issuance of £57 million principal amountof 7.78 percent notes due in 2018.  The2008 Pounds Sterling Senior Notes are unsecured and rank equally with PWPL’s bank credit facilities, the 2007 Senior Notes and the 2008 Senior Notes. The proceeds of theprivate placement of the 2008 Pounds Sterling Senior Notes were used to repay aportion of the indebtedness outstanding under our bankcredit facilities.

 

*Revisions to Alberta Royalty Regime*

 

In December 2008,the Government of Alberta passed into law a “New Royalty Framework” whichintroduces new royalty rates for conventional oil, natural gas and bitumen effectiveJanuary 1, 2009 that are sensitive to price and production levels and willapply to both new and existing oil sands projects and conventional oil and gasactivities. Certain transitional rates and short-term incentives outside of theNew Royalty Framework have also been provided by the Government of Alberta. In2008, approximately 55% of our aggregate crude oil and natural gas productionwas from Alberta Crown leases. The net reserves volumes and estimated netpresent value of future net revenue attributable to our reserves located inAlberta contained in the reserves reported in Appendix A-3 to this AnnualInformation Form reflect Alberta’s New Royalty Framework. For additionalinformation, see the following: “Industry Conditions – Provincial Royalties andIncentives - Alberta” in this Annual Information Form; “Risk Factors” in thisAnnual Information Form; and “TheNew Alberta Royalty Framework” set forth in our management’s discussion andanalysis for the year ended December 31, 2008 (available on SEDAR atwww.sedar.com and on EDGAR at www.sec.gov), which disclosure is incorporatedherein by reference.

 

***Recent Developments***

 

*Public Offering of Trust Units*

 

On February 5, 2009, Penn West completed a public offering of 17.7 million Trust Units at a priceof $14.10 per Trust Unit for aggregate gross proceeds of approximately $250million.  The offering was underwritten by a syndicateof underwriters.  The net proceeds of theoffering were used by Penn West to partially fund capital expenditures and toreduce its indebtedness.  The Trust Units were issued by way of a prospectus supplement thatwas filed with securities regulatory authorities in Canada and the U.S. underPenn West’s short form base shelf prospectus dated June 13, 2008, whichwas previously filed with securities regulatory authorities across Canada andin the U.S. under the multi-jurisdictional disclosure system.

 

*Acquisitions and Dispositions*

* *

To date, we have completed propertydispositions, net of acquisitions, of approximately $137****million in 2009.

 

*Reece Acquisition*

 

On March 10, 2009, Penn West announcedits intention to add to its position in the Dodsland area of Saskatchewan withthe acquisition of Reece Energy Exploration Corp. (“**Reece**”) for a purchase price of approximately $92 million.  Penn West will issue approximately 4.6million Trust Units and assume approximately $40 million of debt in connectionwith the acquisition. The acquisition will add approximately 2,100 boe/d ofproduction, of which approximately 67 percent is light oil, and approximately75,000 net acres of undeveloped land, a significant portion of which iscontiguous with our land position in the Dodsland area.  The acquisition is currently scheduled toclose on April 30, 2009, subject to the satisfaction of various industrystandard closing conditions and the receipt of all necessary regulatory andother third party approvals, including the approval of Reece’s shareholders andthe Court of Queen’s Bench of Alberta.

 

**Significant Acquisitions**

** **

There were nosignificant acquisitions completed by Penn West during the financial year endedDecember 31, 2008 for which disclosure was required under Part 8 ofNational Instrument 51-102, other than the Canetic Acquisition.  For a description of the Canetic Acquisition,see “General Development of the Business – History and Development –Year Ended December 31, 2008 - Canetic Acquisition” above.  Penn West has filed a Form 51-102F4 –Business Acquisition Report in respect of the Canetic Acquisition.

 

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**DESCRIPTION OF OUR BUSINESS**

** **

**Overview**

** **

Our principal undertaking is to issue TrustUnits and to acquire and hold securities of Subsidiaries, net profitsinterests, royalties, notes and other interests.  Our direct and indirect Subsidiaries carry onthe business of acquiring, developing, exploiting and holding interests inpetroleum and natural gas properties and assets related thereto.  A portion of the funds flow from the assetsis paid from PWPL and our other Operating Entities to us by way of interest andprincipal payments on the Internal Notes and payments under the NPI Agreements.

 

The Board of Directors may declaredistributions payable to the Unitholders and allocate all or any of our incometo the Unitholders.  It is currentlyanticipated that the only income we will receive will be from PWPL and ourother Operating Entities by way of interest received on the principal amount ofthe Internal Notes and payments pursuant to the NPIs.  We make monthly cash distributions to Unitholdersfrom this income after any expenses and any cash redemptions of Trust Units.

 

Cash distributions are made on or aboutthe 15th day of each month to Unitholders of record onor about the last calendar day of the immediately preceding month.

 

As at March 26, 2009, we had approximately 1,950****employees.

 

**PWPL**

** **

PWPL is a corporation amalgamated andsubsisting pursuant to the laws of Alberta. PWPL is actively engaged in the business of oil and natural gasexploitation, development, acquisition and production in Canada.  The Trust is the sole shareholder ofPWPL.  The registered and head office ofPWPL is located at Suite 200, 207 – 9th Avenue S.W., Calgary, Alberta, T2P 1K3.

 

**Internal Notes**

** **

The Internal Notes evidence the indebtednessof PWPL and certain other Operating Entities to Penn West.  The Internal Notes are payable on demand, areunsecured, and are subordinated to senior indebtedness and bear interest atrates ranging from****six percent per annum to 13 percent per annum and requireprincipal payments at dates ranging from May 31, 2017 to January 1, 2019.

 

**NPIs**

** **

The Trust is a party to NPI Agreements withPWPL and certain other Operating Entities pursuant to which we have the rightto receive the NPIs on petroleum and natural gas rights held by PWPL and theother Operating Entities from time to time. Pursuant to the terms of the agreements, we are entitled to a paymentfrom PWPL and the other Operating Entities for each month equal to the amountby which 99 percent of the gross proceeds from the sale of productionattributable to the property interests of PWPL and the other Operating Entitiesfor such month exceeds 99 percent of certain deductible costs for suchperiod.  Deductible costs generallyinclude capital expenditures, royalties, operating costs and certain interestexpensesrelated tooil and gas activities.  The term of theagreements is for as long as there are petroleum and natural gas rights towhich the NPIs apply.

 

**Reserves Data**

** **

SeeAppendices A-1, A-2 and A-3 for complete NI 51-101 oil and gas reservesdisclosure for Penn West as at December 31, 2008.

 

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**CAPITALIZATION OF PWPL**

** **

**Common Shares**

** **

PWPL has authorized for issuance an unlimitednumber of common shares.  The Trust ownsall of the issued common shares.  Thevoting of such shares is delegated to the Board of Directors under the TrustIndenture other than:  (i) any sale,lease or other disposition of, or any interest in, all or substantially all ofthe Trust’s assets, except in conjunction with an internal reorganization ofthe Trust’s direct or indirect assets as a result of which the Trust has thesame, or substantially similar, interest, whether direct or indirect, in theassets as the interest, whether direct or indirect, that it had prior to thereorganization; (ii) any statutory amalgamation of PWPL with any otherentity, except in conjunction with an internal reorganization as referred to inparagraph (i) above; (iii) any statutory arrangement involving PWPL,except in conjunction with an internal reorganization as referred to inparagraph (i) above; (iv) any amendment to the articles of PWPL toincrease or decrease the minimum or maximum number of directors; or (v) anymaterial amendment to the articles of PWPL to change the authorized sharecapital or amend the rights, privileges, restrictions and conditions attachingto any class of PWPL’s shares in a manner which may be prejudicial to PennWest, without the approval of the Unitholders by special resolution at ameeting of Unitholders called for that purpose.

 

The holders of common shares are entitled toreceive notice of and to attend all meetings of the shareholders of PWPL and toone vote at such meetings.  The holdersof common shares will be, at the discretion of the Board of Directors andsubject to applicable legal restrictions, entitled to receive any dividendsdeclared by the Board of Directors on the common shares. The holders of commonshares will be entitled to share equally in any distribution of the assets ofPWPL upon the liquidation, dissolution, bankruptcy or winding-up of PWPL orother distribution of its assets among its shareholders for the purpose ofwinding-up its affairs subject to the rights, privileges, restrictions andconditions attaching to any other shares having priority over the commonshares.

 

**Preferred Shares**

** **

PWPL isauthorized to issue an unlimited number of preferred shares in series.  Before any shares of a particular series areissued, the Board of Directors shall, by resolution, fix the number of sharesthat will form such series and shall, subject to the limitations set outherein, by resolution fix the designation, rights, privileges, restrictions andconditions to be attached to the preferred shares of such series.  The preferred shares of each series shallrank on a parity with the preferred shares of every other series with respectto accumulated dividends and return of capital. The preferred shares are entitled to a preference over the common sharesand over any other shares of PWPL ranking junior to the preferred shares with respect to the paymentof dividends and the distribution of assets in the event of the liquidation,dissolution or winding-up of PWPL, whether voluntary or involuntary, or any other distribution of theassets of PWPL among its shareholders for the purpose of winding-up its affairs.

 

The Board of Directors has authorized one series of preferred shares,being the first preferred shares series A (the “**Series A Preferred Shares**”).  One thousand Series A Preferred Shareshave been authorized for issuance. Holders of Series A Preferred Shares are entitled to receivepreferential cash dividends in such amounts as may be declared by the Board ofDirectors.  The payment of such dividendsis in priority to dividends on the common shares of PWPL and all other sharesranking junior to the Series A Preferred Shares with respect to thepayment of dividends.  PWPL has the rightto redeem at any time all, or from time to time any part, of the thenoutstanding Series A Preferred Shares at a price per share equal to$1,000, together with all accrued and unpaid dividends thereon up to the datefixed for redemption.  Each registeredholder of Series A Preferred Shares is entitled to require PWPL to retractat any time any Series A Preferred Shares tendered at a price per shareequal to $1,000, together with all accrued and unpaid dividends thereon up tothe retraction date.  In the event of theliquidation, dissolution or winding-up of PWPL or other distribution of theassets of PWPL among its shareholders for thepurpose of winding-up its affairs,the holders of Series A Preferred Shares are entitled to receive an amountper Series A Preferred Share equal to $1,000 per share, together with anyaccrued and unpaid dividends to the date of commencement of such event, to bepaid all such money before any money shall be paid or property or assetsdistributed to the holders of any common shares of PWPL or other shares in thecapital of PWPL ranking junior to the Series A Preferred Shares withrespect to return of capital.  Afterpayment of the aforementioned amount, the Series A Preferred Shares shallnot be entitled to share in any further distribution of the property or assetsof PWPL.  So long as any Series APreferred Shares are outstanding PWPL may not, without the approval of theholders of the Series A Preferred Shares, take certain actions unless alldividends which have been declared have been paid or set apart forpayment.  Subject to applicable law, theholders of the Series A Preferred Shares are not entitled as such to anyvoting rights or to receive notice of or to attend any meeting of the

 

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shareholders of PWPL or to vote at any such meeting, except for meetingsat which holders of a specified class or series of shares of PWPL are entitledor required to vote separately as a class or series pursuant to the provisionsof the ABCA.

 

As at the date hereof, no preferred shares are issued and outstanding.

 

**Borrowing**

** **

We borrow funds from time to time to financethe purchase of properties, for capital expenditures or for other financialobligations or expenditures in respect of properties held by us or for workingcapital purposes.

 

Certain debt service charges on borrowedfunds attributable to our properties will be deducted in computing income underthe NPIs.  Capital expenditures and anydebt repayment will be scheduled to minimize any income tax payable by PWPL.

 

**INFORMATION RELATING TO PENN WEST**

** **

**Trust Units**

** **

An unlimited number of Trust Units may beissued pursuant to the Trust Indenture. The Trust Units represent equal undivided beneficial interests in PennWest.  All Trust Units share equally inall distributions made by Penn West and all Trust Units carry equal votingrights at meetings of Unitholders.  NoUnitholder will be liable to pay any further calls or assessments in respect ofthe Trust Units.  No conversion,retraction or pre-emptive rights attach to the Trust Units.

 

As at March 26, 2009, approximately 408,249,304million Trust Units were outstanding, approximately 6,020,546 million Trust Units were reserved for issuance onconversion of the Convertible Debentures and approximately 37,367,950 million Trust Units wereavailable for future issuance pursuant to Penn West’s trust unit rightsincentive plan and employee stock savings plan (subject to increase inaccordance with such plans).

 

**Special Voting Units**

** **

The Trust Indenture also provides for theissuance of special voting units which are entitled to such number of votes atmeetings of Unitholders and any other rights or limitations prescribed by theBoard of Directors when the Board of Directors authorizes issuing such specialvoting units.  The Trust Units and thespecial voting units vote together as a single class on all matters.  In the event of Penn West’s liquidation,dissolution or winding-up, the holders of special voting units will not beentitled to receive any of Penn West’s assets available for distribution toUnitholders.  The holders of specialvoting units will not be entitled to receive dividends or other distributionsfrom Penn West.

 

**Convertible Debentures**

** **

Penn West has five series of convertibledebentures outstanding: (i) the 8% 2004 Debentures, (ii) the 8% 2005Debentures, (iii) the 6.5% 2005 Debentures, (iv) the 7.2% Debentures,and (v) the 6.5% 2006 Debentures. The 7.2% Debentures and the 8% 2005 Debentures were assumed by Penn Westpursuant to the Vault Acquisition, which closed on January 10, 2008.  The 6.5% 2005 Debentures, the 6.5% 2006Debentures and the 8% 2004 Debentures were assumed by Penn West pursuant to theCanetic Acquisition, which closed on January 11, 2008.  The following is a summary of the materialattributes and characteristics of the Convertible Debentures.

 

The 8% 2004 Debentures were originally issuedin the aggregate principal amount of $75 million and approximately $7 million principal amount wasoutstanding at March 26,2009.  The 8% 2004 Debentures mature on August 31,2009.

 

The 8% 2005 Debentures were originally issuedin the aggregate principal amount of $55 million and approximately $10 million principal amount wasoutstanding at March 26,2009.  The 8% 2005 Debentures mature on June 30,2010.

 

The 6.5% 2005 Debentures were originallyissued in the aggregate principal amount of $60 million and approximately $18 million principal amount wasoutstanding at March 26,2009.  The 6.5% 2005 Debentures mature onJuly 31, 2010.

 

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The7.2% Debentures were originally issued in the aggregate principal amount of $50million and approximately $26 millionprincipal amount was outstanding at March 26, 2009.  The 7.2%Debentures mature on May 31, 2011.

 

The6.5% 2006 Debentures were originally issued in the aggregate principal amountof $230 million and $229 millionprincipal amount was outstanding at March 26, 2009.  The 6.5% 2006Debentures mature on December 31, 2011.

 

***Terms of Convertible Debentures***

*** ***

The8% 2004 Debentures bear interest from the date of issue at 8% per annum, whichis payable semi-annually in arrears on February 28 and August 31 ineach year.  The 8% 2005 Debentures bearinterest from the date of issue at 8% per annum, which is payable semi-annuallyin arrears on June 30 and December 31 in each year.  The 6.5% 2005 Debentures bear interest fromthe date of issue at 6.5% per annum, which is payable semi-annually in arrearson January 31 and July 31 in each year.  The 7.2% Debentures bear interest from thedate of issue at 7.2% per annum, which is payable semi-annually in arrears on May 31and November 30 in each year.  The6.5% 2006 Debentures bear interest from the date of issue at 6.5% per annum,which is payable semi-annually in arrears on June 30 and December 31in each year.

 

Theprincipal amount of the Convertible Debentures is payable in lawful money ofCanada or, at the option of the Trust and subject to applicable regulatoryapproval, by payment of Trust Units as further described under “Payment UponRedemption or Maturity” and “Redemption and Purchase”.  The interest on the Convertible Debentures ispayable in lawful money of Canada and, in the case of certain of theConvertible Debentures, at the option of the Trust and subject to applicableregulatory approval, in accordance with the Interest Obligation as describedunder “Interest Payment Option”.

 

TheConvertible Debentures are direct obligations of the Trust and are not securedby any mortgage, pledge, hypothec or other charge and are subordinated to otherliabilities of the Trust as described under “Subordination”.  The indentures governing the ConvertibleDebentures do not restrict the Trust from incurring additional indebtedness forborrowed money or from mortgaging, pledging or charging its properties to secureany indebtedness.

 

***Conversion Privilege***

*** ***

The8% 2004 Debentures are convertible at the holder’s option into fully paid andnon-assessable Trust Units at any time prior to the close of business on theearlier of August 31, 2009, and the last business day immediatelypreceding the date specified by Penn West for redemption of the 8% 2004Debentures, at a conversion price of $30.2136 per Trust Unit, being aconversion rate of approximately 33.0977 Trust Units for each $1,000 principalamount of 8% 2004 Debentures.

 

The8% 2005 Debentures are convertible at the holder’s option into fully paid andnon-assessable Trust Units at any time prior to the close of business on theearlier of June 30, 2010 and the last business day immediately precedingthe date specified by Penn West for redemption of the 8% 2005 Debentures, at aconversion price of $82.14 per Trust Unit, being a conversion rate ofapproximately 12.1743 Trust Units for each $1,000 principal amount of 8% 2005Debentures.

 

The6.5% 2005 Debentures are convertible at the holder’s option into fully paid andnon-assessable Trust Units at any time prior to the close of business on theearlier of July 31, 2010 and the last business day immediately precedingthe date specified by Penn West for redemption of the 6.5% 2005 Debentures, ata conversion price of $36.8155 per Trust Unit, being a conversion rate ofapproximately 27.1625 Trust Units for each $1,000 principal amount of 6.5% 2005Debentures.

 

The7.2% Debentures are convertible at the holder’s option into fully paid andnon-assessable Trust Units at any time prior to the close of business on theearlier of May 31, 2011 and the last business day immediately precedingthe date specified by Penn West for redemption of the 7.2% Debentures, at aconversion price of $75.00 per Trust Unit, being a conversion rate ofapproximately 13.3333 Trust Units for each $1,000 principal amount of 7.2%Debentures.

 

The6.5% 2006 Debentures are convertible at the holder’s option into fully paid andnon-assessable Trust Units at any time prior to the close of business on theearlier of December 31, 2011, and the last business day immediatelypreceding the date specified by Penn West for redemption of the 6.5% 2006Debentures, at a conversion price of $51.5534 per Trust Unit, being aconversion rate of approximately 19.3974 Trust Units for each $1,000 principalamount of 6.5% 2006 Debentures.

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***Redemption and Purchase***

*** ***

The8% 2004 Debentures may be redeemed in whole or in part from time to time at theoption of the Trust on not more than 60 days and not less than 40 days priornotice, at a redemption price of $1,025 per 8% 2004 Debenture before maturity(each an “**8% 2004 Redemption Price**”),plus accrued and unpaid interest thereon, if any.

 

Priorto maturity, debenture holders may cause the Trust to redeem the 8% 2005Debentures in whole or in part from time to time, on not more than 60 days andnot less than 30 days prior notice, at a redemption price of $1,050 per 8% 2005Debenture before July 1, 2009, and a redemption price of $1,025 per 8%2005 Debenture on or after July 1, 2009 and before maturity (each an “**8% 2005 Redemption Price**”), in each case,plus accrued and unpaid interest thereon, if any.

 

TheTrust may, on not more than 60 days and not less than 30 days prior notice,redeem the 6.5% 2005 Debentures at a redemption price of $1,050 per 6.5% 2005Debenture on or before July 31, 2009, and at a price of $1,025 per 6.5%2005 Debenture after July 31, 2009 and before July 31, 2010 (each a “**6.5% 2005 Redemption Price**”), plus accruedand unpaid interest thereon, if any.

 

The6.5% 2006 Debentures are not redeemable on or before December 31,2009.  After December 31, 2009 andprior to maturity, the 6.5% 2006 Debentures may be redeemed in whole or in partfrom time to time at the option of the Trust on not more than 60 days and notless than 30 days prior notice, at a redemption price of $1,050 per 6.5% 2006Debenture after December 31, 2009 and on or before December 31, 2010and at a redemption price of $1,025 per 6.5% 2006 Debenture after December 31,2010 and before maturity (each a “**6.5% 2006Redemption Price**”) in each case, plus accrued and unpaid interestthereon, if any.

 

The7.2% Debentures are not redeemable on or before May 31, 2009.  The Trust may, on not more than 60 days andnot less than 30 days prior notice, redeem the 7.2% Debentures at a redemptionprice of $1,050 per 7.2% Debenture after May 31, 2009 and on or before May 31,2010, and a price of $1,025 per 7.2% Debenture after May 31, 2010 andbefore May 31, 2011 (each a “**7.2%Redemption Price**”), plus accrued and unpaid interest thereon, ifany.

 

TheTrust has the right to purchase Convertible Debentures in the market, by tenderor by private contract.

 

***Payment upon Redemption or Maturity***

*** ***

Onredemption or at maturity, the Trust will repay the indebtedness represented bythe Convertible Debentures by paying to the Debenture Trustee in lawful moneyof Canada an amount equal to the aggregate applicable redemption price of theoutstanding Convertible Debentures which are to be redeemed or the principalamount of the outstanding Convertible Debentures which have matured togetherwith accrued and unpaid interest thereon up to but excluding the date ofredemption or maturity, as applicable. The Trust may, at its option, and subject to applicable regulatoryapproval, elect to satisfy its obligation to pay the applicable redemptionprice of the Convertible Debentures which are to be redeemed or the principalamount of the Convertible Debentures which have matured, as the case may be, byissuing Trust Units to the holders of the Convertible Debentures.  Any accrued and unpaid interest thereon willbe paid in cash.  The number of TrustUnits to be issued will be determined by dividing the aggregate applicableredemption price of the outstanding Convertible Debentures which are to beredeemed or the principal amount of the outstanding Convertible Debentureswhich have matured, as the case may be, by 95 percent of the Current MarketPrice of the Trust Units on the date fixed for redemption or the maturity date,as the case may be.  The term “**Current Market Price**” is defined in theConvertible Debenture indentures to mean the weighted average trading price ofthe Trust Units on the TSX for the 20 consecutive trading days ending on thefifth trading day preceding the date fixed for redemption or the maturity date,as the case may be.

 

***Subordination***

*** ***

Thepayment of the principal of, and interest on, the Convertible Debentures issubordinated in right of payment, as set forth in the Debenture Indentures, tothe prior payment in full of all Senior Indebtedness of the Trust.  “**SeniorIndebtedness**” of the Trust is defined in the Debenture Indentures asthe principal of and premium, if any, and interest on and other amounts inrespect of all indebtedness of the Trust (whether outstanding as at the date ofthe Debenture Indentures or thereafter incurred) which includes anyindebtedness to trade creditors, other than indebtedness evidenced by theConvertible Debentures and all other existing and future debentures or otherinstruments of the Trust which, by the terms of the instrument creating or 

 

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evidencingthe indebtedness, is expressed to be *paripassu* with, or subordinate in right of payment to, the ConvertibleDebentures.

 

TheDebenture Indentures provide that in the event of any insolvency or bankruptcyproceedings, or any receivership, liquidation, reorganization or other similarproceedings relative to the Trust, or to its property or assets, or in theevent of any proceedings for voluntary liquidation, dissolution or otherwinding-up of the Trust, whether or not involving insolvency or bankruptcy, orany marshalling of the assets and liabilities of the Trust, then those holdersof Senior Indebtedness, including any indebtedness to trade creditors, willreceive payment in full before the holders of Convertible Debentures will beentitled to receive any payment or distribution of any kind or character,whether in cash, property or securities, which may be payable or deliverable inany such event in respect of any of the Convertible Debentures or any unpaidinterest accrued thereon.  The DebentureIndentures also provide that the Trust will not make any payment, and theholders of the Convertible Debentures will not be entitled to demand, instituteproceedings for the collection of, or receive any payment or benefit(including, without any limitation, by set-off, combination of accounts or realizationof security or otherwise in any manner whatsoever) on account of indebtednessrepresented by the Convertible Debentures (a) in a manner inconsistentwith the terms (as they exist on the date of issue) of the ConvertibleDebentures or (b) at any time when an event of default has occurred underthe Senior Indebtedness and is continuing and the notice of such event ofdefault has been given by or on behalf of the holders of Senior Indebtedness tothe Trust, unless the Senior Indebtedness has been repaid in full.

 

TheConvertible Debentures are effectively subordinate to claims of creditors ofthe Trust’s Subsidiaries except to the extent the Trust is a creditor of suchSubsidiaries ranking at least *pari passu*with such other creditors.  Specifically,the Convertible Debentures are subordinated in right of payment to the priorpayment in full of all indebtedness under the Trust’s credit facilities and tothe prior payment in full of PWPL’s 2007 Senior Notes, 2008 Senior Notes and2008 Pounds Sterling Senior Notes.

 

***Priority over Trust Distributions***

*** ***

TheDebenture Indentures provide that certain expenses of the Trust must bededucted in calculating the amount to be distributed to the Unitholders.  Accordingly, the funds required to satisfythe interest payable on the Convertible Debentures, as well as the amountpayable upon redemption or maturity of the Convertible Debentures or upon anEvent of Default (as defined below), will be deducted and withheld from theamounts that would otherwise be payable as distributions to Unitholders.

 

***Change of Control of the Trust***

*** ***

Within30 days following the occurrence of a change of control of the Trust involvingthe acquisition of voting control or direction over 662/3 percent or more of the TrustUnits (a “**Change of Control**”), theTrust is required to make an offer in writing to purchase all of theConvertible Debentures then outstanding (the “**DebentureOffer**”), at a price equal to 101 percent of the principalamount thereof plus accrued and unpaid interest (the “**Debenture Offer Price**”).

 

If90 percent or more of the aggregate principal amount of any series ofConvertible Debentures outstanding on the date of the giving of notice of theChange of Control have been tendered to the Trust pursuant to the applicableDebenture Offer, the Trust will have the right and obligation to redeem all theremaining Convertible Debentures of that series, at the applicable DebentureOffer Price.

 

***Interest Payment Option***

*** ***

TheTrust may elect, from time to time, to satisfy its obligation to pay all or anypart of the interest on the 6.5% 2006 Debentures, the 8% 2004 Debentures andthe 6.5% 2005 Debentures (but, for greater certainty, not the 7.2% Debenturesor the 8% 2005 Debentures) (the “**InterestObligation**”), on the date it is payable under the applicableDebenture Indenture (an “**Interest PaymentDate**”), by delivering sufficient Trust Units to the DebentureTrustee to satisfy all or the part, as the case may be, of the InterestObligation in accordance with the applicable Debenture Indenture (the “**Unit Interest Payment Election**”).  The Debenture Indentures provide that, uponsuch election, the Debenture Trustee shall: (a) accept delivery from theTrust of Trust Units; (b) accept bids with respect to, and consummatesales of, such Trust Units, each as the Trust shall direct in its absolutediscretion; (c) invest the proceeds of such sales in short-term permittedgovernment securities (as defined in the applicable Debenture Indenture) whichmature prior to the applicable Interest Payment Date, and use the 

 

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proceedsreceived from such permitted government securities, together with any proceedsfrom the sale of Trust Units not invested as aforesaid, to satisfy the InterestObligation; and (d) perform any other action necessarily incidentalthereto.

 

Ifa Unit Interest Payment Election is made, the sole right of a holder ofConvertible Debentures in respect of interest will be to receive cash from theDebenture Trustee out of the proceeds of the sale of Trust Units (plus anyamount received by the Debenture Trustee from the Trust attributable to anyfractional Trust Units) in full satisfaction of the Interest Obligation, andthe holder of such Convertible Debentures will have no further recourse to theTrust in respect of the Interest Obligation.

 

***Events of Default***

*** ***

TheDebenture Indentures provide that an event of default (“**Event of Default**”) in respect of theConvertible Debentures will occur if any one or more of the following describedevents has occurred and is continuing with respect of the ConvertibleDebentures: (a) failure for 10 days to pay interest on the ConvertibleDebentures when due; (b) failure to pay principal or premium, if any, onthe Convertible Debentures when due, whether at maturity, upon redemption, bydeclaration or otherwise; (c) certain events of bankruptcy, insolvency orreorganization of the Trust under bankruptcy or insolvency laws; or (d) defaultin the observance or performance of any material covenant or condition of theDebenture Indentures and continuance of such default for a period of 30 daysafter notice in writing has been given by the Debenture Trustee to the Trustspecifying such default and requiring the Trust to rectify the same.  If an Event of Default has occurred and iscontinuing, the Debenture Trustee may, in its discretion, and shall uponrequest of holders of not less than 25 percent of the principal amount of theapplicable Convertible Debentures then outstanding, declare the principal ofand interest on all outstanding such Convertible Debentures to be immediatelydue and payable.  In certain cases, theholders of more than 50 percent of the principal amount of the applicableConvertible Debentures then outstanding may, on behalf of the holders of all suchConvertible Debentures, waive any Event of Default and/or cancel any suchdeclaration upon such terms and conditions as such holders shall prescribe.

 

***Offers for Debentures***

*** ***

TheDebenture Indentures contain provisions to the effect that if an offer is madefor any series of Convertible Debentures, which is a take-over bid for suchseries of Convertible Debentures within the meaning of the *Securities Act* (Alberta) and not less than90 percent of such Convertible Debentures (other than Convertible Debenturesheld at the date of the take-over bid by or on behalf of the offeror orassociates or affiliates of the offeror) are taken up and paid for by theofferor, the offeror will be entitled to acquire the Convertible Debenturesheld by the holders of such series of Convertible Debentures who did not acceptthe offer on the terms offered by the offeror.

 

***Modification***

*** ***

Therights of the holders of the Convertible Debentures may be modified inaccordance with the terms of the Debenture Indentures.  For that purpose, among others, the DebentureIndentures contain certain provisions which will make binding on allConvertible Debenture holders’ resolutions passed at meetings of the holders ofConvertible Debentures by votes cast thereat by holders of not less than 662/3 percent of the principalamount of the Convertible Debentures present at the meeting or represented byproxy, or rendered by instruments in writing signed by the holders of not lessthan 662/3 percent of the principalamount of the Convertible Debentures then outstanding. In certain cases, themodification will, instead or in addition, require assent by the holders of therequired percentage of Convertible Debentures of each particularly affectedseries.

 

***Limitation on Issuance of AdditionalConvertible Debentures***

*** ***

TheDebenture Indentures provide that the Trust shall not issue additionalConvertible Debentures of equal ranking if the principal amount of all issuedand outstanding Convertible Debenture of the Trust exceeds 25 percent of theTotal Market Capitalization of the Trust immediately after the issuance of suchadditional Convertible Debenture.  “**Total Market Capitalization**” is defined inthe Debenture Indentures as the total principal amount of all issued andoutstanding Convertible Debentures of the Trust which are convertible at theoption of the holder into Trust Units plus the amount obtained by multiplyingthe number of issued and outstanding Trust Units by the Current Market Price ofthe Trust Units on the relevant date.

 

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***Limitation on Non-Resident Ownership***

*** ***

TheDebenture Trustee may require declarations as to the jurisdictions in whichbeneficial owners of Convertible Debentures are resident.  If the Debenture Trustee becomes aware as aresult of requiring such declarations as to beneficial ownership, that thebeneficial owners of 49 percent of the Trust Units then outstanding (40 percentin the case of the 6.5% 2006 Debentures and not more than half in the case ofthe 8% 2005 Debentures and the 7.2% Debentures), on a fully diluted basis, are,or may be, Non-Residents or that such a situation is imminent, the DebentureTrustee may make a public announcement thereof and shall not register atransfer of Convertible Debentures to a person unless the person provides adeclaration that the person is not a Non-Resident.  If, notwithstanding the foregoing, theDebenture Trustee determines that a majority of the Trust Units are held byNon-Residents, the Debenture Trustee may send a notice to Non-Resident holdersof Convertible Debentures, chosen in inverse order to the order of acquisitionor registration of the Convertible Debentures or in such manner as theDebenture Trustee may consider equitable and practicable, requiring them tosell their Convertible Debentures or a portion thereof within a specifiedperiod of not less than 60 days.  If theConvertible Debenture holders receiving such notice have not sold the specifiednumber of Convertible Debentures or provided the Debenture Trustee with satisfactoryevidence that they are not Non-Residents within such period, the DebentureTrustee may, on behalf of such holder of Convertible Debentures, and in theinterim shall, suspend the rights attached to such Convertible Debentures.  Upon such sale the affected holders shallcease to be holders of Convertible Debentures, and their rights shall belimited to receiving the net proceeds of sale upon surrender of suchConvertible Debentures.

 

***Book-Entry System for ConvertibleDebentures***

*** ***

TheConvertible Debentures (other than the 8% 2005 Debentures) are issued in“book-entry only” form and must be purchased or transferred through aparticipant in the depository service of CDS & Co.  The Convertible Debentures (other than the 8%2005 Debentures) are evidenced by a single book-entry only certificate.  Registration of interests in and transfers ofthe Convertible Debentures (other than the 8% 2005 Debentures) is made onlythrough the depository service of CDS & Co.

 

The8% 2005 Debentures are issued as fully registered debentures in certificatedform and beneficial holders of 8% 2005 Debentures may receive definitivecertificates representing their interest in 8% 2005 Debentures.

 

**Ratings**

** **

PennWest has not asked for nor has received a stability rating, and it is not awarethat it has received any other kind of rating, including a provisional rating,from one or more approved rating organizations for outstanding securities ofPenn West, which rating or ratings continue in effect.

 

**TrustIndenture**

** **

TheTrust Indenture, among other things, provides for the calling of meetings ofUnitholders, the conduct of business thereof, notice provisions, theappointment and removal of the Trustee and the form of Trust Unitcertificates.  The Trust Indenture may beamended from time to time.  Substantiveamendments to the Trust Indenture, including early termination of the Trust andthe sale or transfer of our property as an entirety or substantially as anentirety, requires approval by special resolution of the Unitholders.  See “Information Relating to the Trust —Meetings and Voting” below.

 

Thefollowing is a summary of certain provisions of the Trust Indenture.  For a complete description of such indenture,reference should be made to the Trust Indenture, a copy of which (including allamendments thereto) has been filed on SEDAR at www.sedar.com.

 

***Trustee***

*** ***

CIBC Mellon Trust Company was appointed our trustee on May 27,2005, and also acts as the transfer agent for the Trust Units.  The Trustee is responsible for, among otherthings, accepting subscriptions for Trust Units and issuing Trust Unitspursuant thereto, maintaining our books and records and providing timelyreports to holders of Trust Units.  TheTrust Indenture provides that the Trustee shall exercise its powers and carryout its functions thereunder as Trustee honestly, in 

 

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good faith and in the Trust’s best interests and in the best interestof the Unitholders and, in connection therewith, shall exercise that degree ofcare, diligence and skill that a reasonably prudent trustee would exercise incomparable circumstances.

 

In 2008, the Unitholders appointed the Trustee for an additionalthree-year term.  The Unitholders arerequired to re-appoint or appoint a successor to the Trustee at the annualmeeting of Unitholders three years following the re-appointment or appointmentof the successor to the Trustee.  TheTrustee may also be removed by special resolution of the Unitholders.  Such resignation or removal becomes effectiveupon the acceptance or appointment of a successor trustee.

 

PWPLpresently administers the Trust on behalf of the Trustee.  PWPL, on behalf of the Trustee, keeps suchbooks and records as are necessary for the proper recording of the Trust’sbusiness transactions.

 

TheTrust Indenture provides that the Trustee shall be under no liability for anyaction or failure to act unless such liabilities arise out of the Trustee’snegligence, wilful default or fraud.  TheTrustee is indemnified out of the Trust’s assets for any liabilities relatingto any taxes or other government charges imposed upon the Trustee or inconsequence of its performance of its duties unless such liabilities ariseprincipally and directly out of gross negligence, wilful default or fraud ofthe Trustee, but has no additional recourse against Unitholders.  In addition, the Trust Indenture containsother customary provisions limiting the liability of the Trustee.

 

TheTrust Indenture also provides that the Trustee may without Unitholder approvalamend the articles of PWPL to issue shares of PWPL which are exchangeable forTrust Units.  There are no exchangeableshares issued or outstanding.

 

***Future Offerings***

*** ***

The Trust Indenture provides that Trust Units, including rights,warrants and other securities to purchase, to convert into or to exchange intoTrust Units, may be created, issued, sold and delivered on such terms andconditions and at such times as the Trustee, upon the recommendation of theBoard of Directors, may determine.  TheTrust Indenture also provides that PWPL may authorize the creation and issuanceof debentures, notes and other evidences of indebtedness by the Trust, whichdebentures, notes or other evidences of indebtedness may be created and issuedfrom time to time on such terms and conditions to such persons and for suchconsideration as the Board of Directors may determine.

 

***Meetings and Voting***

*** ***

Meetingsof the Unitholders will be held annually. Special meetings of Unitholders may be called at any time by the Trusteeand shall be called by the Trustee upon the written request of Unitholdersholding in aggregate not less than 20 percent of the Trust Units.  Notice of all meetings of Unitholders shallbe given to Unitholders at least 21 days prior to the meeting.

 

Unitholderswill be entitled at each annual meeting to appoint the Trust’s auditors and toelect all the members of the Board of Directors.

 

***Our Management***

*** ***

TheBoard of Directors has generally been delegated all of the Trust’s significantmanagement decisions pursuant to the Trust Indenture and the AdministrationAgreement.  For more information, see“Corporate Governance”.

 

PWPLhas accepted all such delegation and has agreed that, in respect of suchmatters, it shall carry out its functions honestly, in good faith and in theTrust’s best interests and the best interests of the Unitholders and, inconnection therewith, shall exercise that degree of care, diligence and skillthat a reasonable person would exercise in comparable circumstances.

 

***Limitation on Non-Resident Ownership***

*** ***

Inorder for the Trust to maintain its status as a mutual fund trust under the TaxAct, it must not be established or maintained primarily for the benefit ofNon-Residents unless it satisfies the requirements of certain exceptions.  The Trust Indenture provides that Penn Westwill use its best commercial efforts to maintain its status as a mutual fundtrust under the Tax Act.  Generallyspeaking, the Tax Act provides that a trust will permanently lose its “mutualfund trust” status (which is essential to the income trust structure) if it isestablished or maintained primarily for the benefit of Non-Residents (which isgenerally 

 

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interpretedto mean that the majority of unitholders must not be Non-Residents), unless atthe relevant time, “all or substantially all” of the trust’s property consistsof property other than taxable Canadian property (the “**TCP Exception**”).  We have determined that Penn West currentlymeets the requirement of the TCP Exception, and as a result, the TrustIndenture does not currently have a specific limit on the percentage of TrustUnits that may be owned by Non-Residents.

 

***Right of Redemption***

*** ***

TrustUnits are redeemable at any time on demand by the holders thereof upon deliveryto the Trust of the certificate or certificates representing such Trust Units,accompanied by a duly completed and properly executed notice requiringredemption.  Upon receipt of the noticeto redeem Trust Units by the Trust, the holder thereof shall only be entitledto receive a price per Trust Unit (the “**MarketRedemption Price**”) equal to the least of: (i) 95 percentof the “market price” of the Trust Units on the principal market on which theTrust Units are quoted for trading during the 10 trading day period commencingimmediately after the date on which the Trust Units are tendered to the Trustfor redemption; (ii) 95 percent of the closing market price on theprincipal market on which the Trust Units are quoted for trading on the datethat the Trust Units are so tendered for redemption; and (iii) 95 percentof the closing market price of the Trust Units on the date of redemption.

 

Forthe purposes of this calculation, “market price” will be an amount equal to thesimple average of the closing price of the Trust Units for each of the tradingdays on which there was a closing price; provided that, if the applicableexchange or market does not provide a closing price but only provides thehighest and lowest prices of the Trust Units traded on a particular day, themarket price shall be an amount equal to the simple average of the****highest and lowest prices for each of thetrading days on which there was a trade; and provided further that if there wastrading on the applicable exchange or market for fewer than five of the 10trading days, the market price shall be the simple average of the followingprices established for each of the 10 trading days: the average of the last bidand last ask prices for each day on which there was no trading; the closingprice of the Trust Units for each day that there was trading if the exchange ormarket provides a closing price; and the average of the highest and lowestprices of the Trust Units for each day that there was trading, if the marketprovides only the highest and lowest prices of Trust Units traded on aparticular day.  The closing market priceshall be: an amount equal to the closing price of the Trust Units if there wasa trade on the date; an amount equal to the average of the highest and lowestprices of the Trust Units if there was trading and the exchange or other marketprovides only the highest and lowest prices of Trust Units traded on aparticular day; and the average of the last bid and last ask prices if therewas no trading on the date.

 

TheMarket Redemption Price payable by the Trust in respect of any Trust Unitstendered for redemption during any calendar month shall be satisfied by way ofcheque payable on the last day of the calendar month following the month inwhich the Trust Units were tendered for redemption.  The entitlement of Unitholders to receive acheque upon the redemption of their Trust Units is subject to the limitationthat the total amount payable by the Trust in respect of such Trust Units andall other Trust Units tendered for redemption in the same calendar month shallnot exceed $250,000 provided that, Penn West may, in its sole discretion, waivesuch limitation in respect of any calendar month.  If this limitation is not so waived, theMarket Redemption Price payable by the Trust in respect of Trust Units tenderedfor redemption in such calendar month shall be paid on the last day of thecalendar month following such month by the Trust distributing redemption notesof PWPL to the Unitholders who exercised the right of redemption.

 

Theredemption notes will be due on the third anniversary of the date of issuanceand will bear interest at a rate per annum to be set by the Board of Directorsin the context of the prevailing interest rates for debt instruments havingequivalent terms and conditions.  Theredemption notes will be issued under a trust indenture and will provide fortheir issuance to the Trust in consideration of cash or as a reduction in theprincipal amount of the Internal Notes issued by PWPL to the Trust.

 

Itis anticipated that this redemption right will not be the primary mechanism forholders of Trust Units to dispose of their Trust Units.  Redemption notes which may be distributed inspecie to Unitholders in connection with a redemption will not be listed on anystock exchange and no market is expected to develop in such redemptionnotes.  Redemption notes may not bequalified investments for trusts governed by registered retirement savingsplans, registered retirement income funds, deferred profit sharing plans,registered disability savings plans, registered education savings plans and taxfree savings accounts.

 

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***Termination of the Trust***

*** ***

TheUnitholders may vote to terminate the Trust at any meeting of the Unitholders,subject to the following: (a) a vote may only be held if requested inwriting by the holders of not less than 20 percent of the Trust Units; (b) aquorum of 50 percent of the issued and outstanding Trust Units is present inperson or by proxy; and (c) the termination must be approved by specialresolution of the Unitholders.

 

Unlessthe Trust is earlier terminated or extended by vote of the Unitholders, theTrustee shall commence to wind-up the affairs of the Trust on December 31,2099.  In the event that the Trust iswound-up, the Trustee will liquidate all of the Trust’s assets, pay, retire,discharge or make provision for some or all of the Trust’s obligations and thendistribute the remaining proceeds of sale to Unitholders.

 

***Reporting to Unitholders***

*** ***

PennWest’s financial statements will be audited annually by an independentrecognized firm of chartered accountants. Our audited financial statements, together with the report of suchchartered accountants, will be mailed by the Trustee to Unitholders ifpreviously requested and, if previously requested, the unaudited interimfinancial statements will be mailed to Unitholders within the periodsprescribed by securities legislation. Penn West’s year end is December 31.  We are also subject to the continuousdisclosure obligations under all applicable securities legislation.

 

Unitholdersare entitled to inspect, during normal business hours, at the offices of theTrustee, and upon payment of reasonable reproduction costs, to receivephotocopies of the Trust Indenture and a listing of the registered holders ofTrust Units.

 

**CORPORATE GOVERNANCE**

** **

**General**

** **

Ingeneral, PWPL has been delegated responsibility for substantially all of themanagement decisions of Penn West.  TheUnitholders are entitled to elect all of the members of the Board of Directorsof PWPL pursuant to the terms of the Trust Indenture.

 

**TrustIndenture**

** **

Pursuantto the Trust Indenture, Unitholders are entitled to direct the manner in whichthe Trust will vote its common shares in PWPL at all meetings in respect ofmatters relating to the election of the directors of PWPL, approving itsfinancial statements and appointing auditors of PWPL who shall be the same asthe Trust’s auditors.  Prior to the Trustvoting its common shares in PWPL in respect of such matters, each Unitholder isentitled to vote in respect of the matter on the basis of one vote per TrustUnit held, and the Trust is required to vote its common shares in PWPL inaccordance with the result of the vote of Unitholders.

 

**DecisionMaking**

** **

TheBoard of Directors has a mandate to supervise the management of the Trust’sbusiness and affairs, PWPL and the Trust’s other direct or indirectSubsidiaries and to act with a view to the Trust’s best interest.  The Board of Directors’ mandateincludes:  (i) any offering ofsecurities; (ii) ensuring compliance with all applicable laws, includingin relation to an offering of securities; (iii) all matters relating tothe content of any documents relating to an offering of securities, theaccuracy of the disclosure contained therein, and the certification thereof; (iv) allmatters concerning the terms of, and amendment from time to time of, materialcontracts; (v) all matters concerning any subscription agreement orunderwriting or agency agreement providing for the sale or issue of Trust Unitsor securities convertible for or exchangeable into Trust Units or rights toacquire Trust Units; (vi) all matters relating to the redemption of TrustUnits; (vii) all matters relating to the voting rights on any investments;(viii) all matters relating to the specific powers and authorities as setforth in the Trust Indenture; (ix) the adoption of a Unitholder rightsplan and other miscellaneous matters relating to the maximization of Unitholdervalue; and (x) all matters relating to amending PWPL’s articles to createexchangeable shares.  The Board ofDirectors holds regularly 

 

27

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scheduledmeetings at least quarterly to review the business and affairs of the Trust’sSubsidiaries and make any necessary decisions relating thereto.

 

TheTrust Indenture gives to the Board of Directors the authority to exercise therights, powers and privileges for all matters relating to the maximization ofUnitholder value in the context of a take-over bid (an “**Offer**”) including any Unitholder rightsprotection plan, any defensive action to an Offer, any directors circular inresponse to an Offer, any regulatory or court proceeding relating to an Offerand any related or ancillary matter.

 

**Distributionsand Distribution Policy**

** **

Cashdistributions are made on the 15th day (orif such date is not a business day, on the preceding business day) followingthe end of each calendar month to Unitholders of record on the last businessday of each such calendar month or such other date as determined from time totime by the Trustee.

 

**The Board of Directors (on behalf of the Trust) reviews thedistribution policy from time to time. Distributions are not guaranteed and the amount that we distribute perTrust Unit on a monthly basis may be reduced from time to time, or eveneliminated. ****The actual amount distributedwill be dependent on various factors, including the commodity priceenvironment, the amount of capital expenditures that we make, our productionlevels and numerous other economic and operational factors, many of which arebeyond our control.  The amount ofdistributions that we make (if any) is at the discretion of the Board of Directorsof PWPL.  See “Risk Factors”.**  The currentdistribution policy targets the use of approximately 60 percent to 70 percent of funds flow for distributionto Unitholders.  Depending upon variousfactors, including commodity prices and the size of Penn West’s capital budget,it is expected that approximately 30 percentto 40 percent of funds flow will fund all or a portion of PennWest’s annual capital expenditure program, including exploration, exploitationexpenditures and minor property acquisitions, but excluding major acquisitions.

 

Distributionsare normally announced on a monthly basis in the context of prevailing andanticipated commodity prices.  Duringperiods of volatile commodity prices, we may vary the distribution ratemonthly.  On January 14, 2009, we announced that inlight of our intended 2009 capital expenditure levels and the continuing weakcommodity price environment, the Board of Directors had approved areduction to our monthly distribution to Unitholders from $0.34 per Trust Unitper month to $0.23 per Trust Unit per month for the next two months (subject tochanges in commodity prices, production levels and capital expenditures),commencing with the distribution paid on February 13, 2009 to Unitholdersof record on January 30, 2009.  On March 26,2009, we subsequently announced that in light of our revised 2009 capitalexpenditure levels and the continuing weak commodity price environment, the Boardof Directors had approved a further reduction to our monthly distribution toUnitholders from $0.23 per Trust Unit per month to $0.15 per Trust Unit permonth, subject to changes in commodity prices, production levels and capitalexpenditures, commencing with the distribution to be paid on May 15, 2009 toUnitholders of record on April 30, 2009.

 

Pursuantto the provisions of the Trust Indenture all taxable income earned by Penn Westin a fiscal year, not previously distributed in that fiscal year, must bedistributed to Unitholders of record on December 31 of such year.  This excess income, if any, will be allocatedto Unitholders of record at December 31 but the right to receive thisincome, if the amount is not determined and declared payable at December 31,will trade with the Trust Units until determined and declared payable inaccordance with the rules of the TSX. To the extent that a Unitholder trades Trust Units in this period theywill be allocated such income but will dispose of their right to receive thecash or Trust Units comprising such a distribution.

 

Thecredit agreement governing PWPL’s syndicated credit facility and the notepurchase agreements governing PWPL’s 2007 Senior Notes, 2008 Senior Notes and2008 Pounds Sterling Senior Notes each contain provisions which restrict theability of the Trust to pay distributions to Unitholders in the event of theoccurrence of certain events of default. For further information regarding the credit agreement governing oursyndicated credit facility, reference is made to Note 6 (Long-Term Debt) of our consolidated financial statements forthe year ended December 31, 2008. For further information regarding the note purchase agreements governingPWPL’s 2007 Senior Notes, 2008 Senior Notes and 2008 Pounds Sterling SeniorNotes, reference is made to note 6(Long-Term Debt) of our consolidated financial statements for the year ended December 31,2008.  Note 6 (Long-Term Debt) of our consolidated financial statements forthe year ended December 31, 2008 is incorporated by reference in thisAnnual Information Form.  Ourconsolidated financial statements for the year ended December 31, 2008 arefiled on SEDAR at www.sedar.com.

 

28

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**Directors and Executive Officers of PWPL**

** **

The following table sets forth the name,province/state and country of residence and positions and offices held for eachof the directors and executive officers of PWPL, together with their principaloccupations during the last five years. The directors of PWPL will hold office until the next annual meeting ofUnitholders or until their respective successors have been duly elected orappointed.

 
| **Name, Province/State and  Country of Residence** | ** ** | **Positions  and Offices Held**                                        | ** ** | **Principal  Occupations   during the Five Preceding Years**                                                                                                                                                                                                                                                                              |
|----------------------------------------------------|------------|------------------------------------------------------------------------|------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| ** **                                         | ** ** | ** **                                                             | ** ** | ** **                                                                                                                                                                                                                                                                                                                                |
| James E. Allard(1)(5)(6)

Alberta, Canada          |       | Director since June 30, 2006                                      |       | Independent director and business advisor.  Also, a member of the Alberta Securities Commission from 1999 to 2005.                                                                                                                                                                                                                        |
|                                               |       |                                                                   |       |                                                                                                                                                                                                                                                                                                                                      |
| William E. Andrew

Alberta, Canada                 |       | Chief Executive Officer Director since  June 3, 1994              |       | Chief Executive Officer of PWPL since  January 11, 2008. Prior thereto, President and Chief Executive Officer  of PWPL since May 2005. Prior thereto, President of PWPL.                                                                                                                                                        |
|                                               |       |                                                                   |       |                                                                                                                                                                                                                                                                                                                                      |
| Robert G. Brawn(3)(5)

Alberta, Canada             |       | Director since January 11, 2008                                   |       | President of 738831 Alberta Ltd. (a private  investment company) since 2003. Prior thereto, Chairman of Acclaim Energy  Inc. (“**Acclaim**”), the  administrator of Acclaim Energy Trust (a public oil and gas income trust), a  predecessor of Canetic.                                                                        |
|                                               |       |                                                                   |       |                                                                                                                                                                                                                                                                                                                                      |
| George H. Brookman(2)(4) Alberta, Canada           |       | Director since August 3, 2005                                     |       | President and Chief Executive Officer of  West Canadian Industries Group Inc. (a commercial digital printing and  graphics company).                                                                                                                                                                                                      |
|                                               |       |                                                                   |       |                                                                                                                                                                                                                                                                                                                                      |
| John A. Brussa

Alberta, Canada                    |       | Chairman of the Board of Directors Director  since April 21, 1995 |       | Senior Partner, Burnet,  Duckworth & Palmer LLP (barristers and solicitors).                                                                                                                                                                                                                                                     |
|                                               |       |                                                                   |       |                                                                                                                                                                                                                                                                                                                                      |
| Daryl Gilbert(2)(3)(5)

Alberta, Canada            |       | Director since January 11, 2008                                   |       | Independent business consultant since 2005  and a corporate director of a number of companies. President and Chief  Executive Officer of GLJ Petroleum Consultants Ltd. (formerly Gilbert  Laustsen Jung Associates Ltd.) (an engineering consulting firm) until 2005.                                                                    |
|                                               |       |                                                                   |       |                                                                                                                                                                                                                                                                                                                                      |
| Shirley A. McClellan(1)(4)(5) Alberta,  Canada     |       | Director since June 8, 2007                                       |       | Distinguished Scholar in Residence at the  University of Alberta for the Faculties of Agriculture and Rural Economy and  the School of Business. Independent businesswoman since 2007. Prior thereto,  Deputy Premier of the Province of Alberta from 2001 to 2007 and Minister of  Finance of the Province of Alberta from 2004 to 2007. |
|                                               |       |                                                                   |       |                                                                                                                                                                                                                                                                                                                                      |
| Frank Potter(1)(4)(6)

Ontario, Canada             |       | Director since June 30, 2006                                      |       | Chairman of Emerging Markets  Advisors, Inc. (an investment consulting firm).                                                                                                                                                                                                                                                        |
|                                               |       |                                                                   |       |                                                                                                                                                                                                                                                                                                                                      |
| R. Gregory Rich(2)(4)

Texas, United States        |       | Director since January 11, 2008                                   |       | Principal of Blackrock Energy Associates  (an energy consulting and investment firm), since October 2002.                                                                                                                                                                                                                            |

 

29

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| **Name, Province/State and  Country of Residence** | ** ** | **Positions  and Offices Held**                                  | ** ** | **Principal  Occupations   during the Five Preceding Years**                                                                                                                                                                                                                                                                                                                                                                                                           |
|----------------------------------------------------|------------|------------------------------------------------------------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                                               |       |                                                             |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
| Jack Schanck(3)(5)

Texas, United States           |       | Director since June 2, 2008                                 |       | Managing Partner of Tecton Energy, LLC  since 2007, a Texas-based oil and  natural gas exploration and production company. Prior thereto, Chief  Executive Officer of SouthView Energy LLC, an oil and natural gas investment  company, from 2005 to 2007.  Prior thereto, Co-Chief Executive Officer of Samson Investment Company.                                                                                                                                    |
|                                               |       |                                                             |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
| James C. Smith(1)(2)(3)

Alberta, Canada           |       | Director since May 31, 2005                                 |       | Independent director and consultant to a  number of public and private oil and gas companies.                                                                                                                                                                                                                                                                                                                                                                          |
|                                               |       |                                                             |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
| Murray Nunns

Alberta, Canada                      |       | President and Chief Operating Officer                            |       | President and Chief Operating Officer of  PWPL since February 8, 2008. Prior thereto, director of PWPL and  Executive Chairman of Monterey Exploration Ltd., a private oil and gas company.  Prior thereto, a variety of management positions at Rio Alto Exploration  Ltd., a public oil and gas company.                                                                                                                                                        |
|                                               |       |                                                             |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
| Todd  H. Takeyasu

Alberta,  Canada                |       | Executive  Vice President and Chief Financial Officer            |       | Executive  Vice President and Chief Financial Officer of PWPL since February 8,  2008. Prior thereto, Senior Vice President, Finance — Treasury of PWPL since  January 11, 2008. Prior thereto, Senior Vice President and Chief  Financial Officer of PWPL since 2006. Prior thereto, Vice President, Finance  of PWPL since 2005. Prior thereto, Treasurer of PWPL.                                                                                    |
|                                               |       |                                                             |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
| David W. Middleton

Alberta, Canada                |       | Executive Vice President, Engineering and  Corporate Development |       | Executive Vice President, Engineering and  Corporate Development of PWPL since November 3, 2008. Prior thereto,  Executive Vice President, Operations and Corporate Development of PWPL since  February 8, 2008. Prior thereto, Chief Operating Officer of PWPL since  January 11, 2008. Prior thereto, Executive Vice President and Chief  Operating Officer of PWPL since 2005. Prior thereto, Senior Vice President,  Production of PWPL since 2003. |
|                                               |       |                                                             |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
| Mark P. Fitzgerald

Alberta, Canada                |       | Senior Vice President, Production                                |       | Senior Vice President, Production of PWPL  since November 3, 2008. Prior thereto, Senior Vice President,  Engineering of PWPL since January 11, 2008. Prior thereto, Vice  President, Operations of Canetic since January 2006. Prior thereto, Vice  President, Operations of Acclaim since February 2005. Prior thereto,  Vice President, Engineering of Acclaim (since 2004) and Manager, Western  District of Acclaim (from 2003 to 2004).      |
|                                               |       |                                                             |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
| Thane A.E. Jensen

Alberta, Canada                 |       | Senior Vice President, Operations  Engineering                   |       | Senior Vice President, Operations  Engineering of PWPL since November 3, 2008. Prior thereto, Senior Vice  President, Exploration and Development of PWPL since 2005. Prior thereto,  Vice President, Engineering of PWPL since 2004.                                                                                                                                                                                                                             |

 

30

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| **Name, Province/State and  Country of Residence** | ** ** | **Positions  and Offices Held**                                   | ** ** | **Principal  Occupations   during the Five Preceding Years**                                                                                                                                                                                                                                                                                                                                                                  |
|----------------------------------------------------|------------|-------------------------------------------------------------------|------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                                               |       |                                                              |       |                                                                                                                                                                                                                                                                                                                                                                                                                          |
| Keith Luft

Alberta, Canada                        |       | General Counsel and Senior Vice President,  Stakeholder Relations |       | General Counsel and Senior Vice President,  Stakeholder Relations of PWPL since February 8, 2008. Prior thereto,  Senior Vice President, Stakeholder Relations of PWPL since January 11,  2008. Prior thereto, Vice President, Land and Legal of PWPL since 2006. Prior  thereto, Senior Solicitor of Conoco Phillips Canada Ltd. / Burlington  Resources Canada Ltd. (an oil and gas company) since May 2004. |
|                                               |       |                                                              |       |                                                                                                                                                                                                                                                                                                                                                                                                                          |
| Hilary  Foulkes

Alberta,  Canada                  |       | Senior  Vice-President, Business Development                      |       | Senior  Vice-President, Business Development of PWPL since April 29, 2008. Prior  thereto, a Managing Director with the investment banking firm, Scotia  Waterous for 8 years. Prior thereto, various positions as a geologist in  exploration and development roles with Gulf Canada Resources.                                                                                                                         |

 

----

Notes:

 

(1)          Member of the Audit Committee of the Boardof Directors.

(2)          Member of the Human Resources andCompensation Committee of the Board of Directors.

(3)          Member of the Reserves Committee of theBoard of Directors.

(4)          Member of the Governance Committee of theBoard of Directors.

(5)          Member of the Health, Safety andEnvironment Committee of the Board of Directors.

(6)          Member of the Acquisitions and DivestmentsCommittee of the Board of Directors.

 

As at March 26, 2009, the directors and executive officers of PWPL, as agroup, beneficially owned, or controlled or directed, directly or indirectly, approximatelyone million Trust Units or less than onepercent of the issued and outstanding Trust Units.

 

**Cease TradeOrders, Bankruptcies, Penalties or Sanctions**

** **

Except as otherwise disclosed herein,****no director or executive officer of PWPL(nor any personal holding company of any of such persons) is, as of the date ofthis Annual Information Form, or was within ten years before the date of thisAnnual Information Form, a director, Chief Executive Officer or Chief FinancialOfficer of any company (including PWPL), that:

 

(a)                                  was subject to a cease trade order (including a management ceasetrade order), an order similar to a cease trade order or an order that deniedthe relevant company access to any exemption under securities legislation, ineach case that was in effect for a period of more than 30 consecutive days(collectively, an “**Order**”) thatwas issued while the director or executive officer was acting in the capacityas director, Chief Executive Officer or Chief Financial Officer; or

 

(b)                                 was subject to an Order that was issued after the director orexecutive officer ceased to be a director, Chief Executive Officer or ChiefFinancial Officer and which resulted from an event that occurred while thatperson was acting in the capacity as director, Chief Executive Officer or ChiefFinancial Officer.

 

Daryl Gilbert is a director of Globel Direct, Inc.,which was subject to a cease trade order issued by the British ColumbiaSecurities Commission on November 20, 2002 and the Alberta SecuritiesCommission on November 22, 2002 for delay in filing financialstatements.  The required financialstatements were filed and the cease trade orders were revoked effective December 23,2002.  The company sought and receivedprotection under CCAA in June 2007, and after a failed restructuringeffort, a receiver was appointed by one of the company’s lenders in December 2007.  The company has since ceased operations andis delisted.

 

31

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Except as otherwise disclosed herein, no directoror executive officer of PWPL (nor any personal holding company of any of suchpersons), or shareholder holding a sufficient number of securities of Penn Westto affect materially the control of Penn West:

 

(a)                                  is, as of the date of this Annual Information Form, or has beenwithin the ten years before the date of this Annual Information Form, adirector or executive officer of any company (including PWPL) that, while thatperson was acting in that capacity, or within a year of that person ceasing to actin that capacity, became bankrupt, made a proposal under any legislationrelating to bankruptcy or insolvency or was subject to or instituted anyproceedings, arrangement or compromise with creditors or had a receiver,receiver manager or trustee appointed to hold its assets; or

 

(b)                                 has, within the ten years before the date of this Annual InformationForm, become bankrupt, made a proposal under any legislation relating tobankruptcy or insolvency, or become subject to or instituted any proceedings,arrangement or compromise with creditors, or had a receiver, receiver manageror trustee appointed to hold the assets of the director, executive officer orshareholder.

 

John A. Brussa was a director of ImperialMetals Limited, a corporation engaged in both oil and gas and miningoperations, in the year prior to that corporation implementing a plan ofarrangement under the *Company Act*(British Columbia) and under the *Companies’Creditors Arrangement Act* (Canada) which resulted in the separationof its two businesses.  Thereorganization resulted in the creation of two public corporations, ImperialMetals Corporation and IEI Energy Inc. (subsequently renamed Rider ResourcesLtd.), both of which were listed on the TSX.

 

James C. Smith was, from May 1999 to March 2000,Vice President and Chief Financial Officer of Probe Exploration Inc., an oiland gas company listed on the TSX.  Mr. Smithjoined Probe Exploration Inc. in order to assist management and the Board ofDirectors of the company in their efforts to restructure the company’s financesor sell assets to improve its financial situation.  Such efforts did not succeed and thecompany’s lender appointed a receiver in March 2000.

 

No director or executive officer of PWPL (norany personal holding company of any of such persons), or shareholder holding asufficient number of securities of Penn West to affect materially the controlof Penn West, has been subject to:

 

(a)                                  any penalties or sanctions imposed by a court relating to securitieslegislation or by a securities regulatory authority or has entered into asettlement agreement with a securities regulatory authority; or

 

(b)                                 any other penalties or sanctions imposed by a court or regulatorybody that would likely be considered important to a reasonable investor inmaking an investment decision.

 

**Conflicts of Interest**

** **

The Board of Directors has adopted a Code ofBusiness Conduct and Ethics and a Code of Ethics for Officers and SeniorFinancial Management (the “**Codes**”).  In general, the private investment activitiesof employees, directors and officers are not prohibited; however, should anexisting investment pose a potential conflict of interest, the potentialconflict is required by the Codes to be disclosed to the President, ChiefExecutive Officer or the Board of Directors. Any other activities posing a potential conflict of interest are alsorequired by the Codes to be disclosed to the Chief Executive Officer or theBoard of Directors.  Any such potentialconflicts of interests will be dealt with openly with full disclosure of thenature and extent of the potential conflicts of interests with Penn West.

 

It is acknowledged in the Codes that thedirectors may be directors or officers of other entities engaged in the oil andgas business, and that such entities may compete directly or indirectly withPenn West.  Passive investments in publicor private entities of less than one per cent of the outstanding shares willnot be viewed as “competing” with Penn West. No executive officer or employee of PWPL should be a director or officerof any entity engaged in the oil and gas business unless expressly authorizedby the Board of Directors.  Any directorof PWPL who is actively engaged in the management of, or who owns an investmentof one per cent or more of the outstanding shares, in public or privateentities shall disclose such holding to the Board of Directors.  In the event that any circumstance shouldarise as a result of such positions or investments being held or otherwisewhich in the opinion of the Board of Directors constitutes a conflict ofinterest which reasonably affects such person’s ability to act with a view tothe best interests of Penn West, the Board of Directors will take such actions

 

32

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as are reasonably required to resolve suchmatters with a view to the best interests of Penn West.  Such actions, without limitation, may includeexcluding such directors, officers or employees from certain information oractivities of Penn West.

 

The ABCA provides that in the event that anofficer or director is a party to, or is a director or an officer of, or has amaterial interest in any person who is a party to, a material contract ormaterial transaction or proposed material contract or proposed material transaction,such officer or director shall disclose the nature and extent of his or herinterest and shall refrain from voting to approve such contract or transaction.

 

As of the date hereof, Penn West is not awareof any existing or potential material conflicts of interest between Penn Westor a Subsidiary of Penn West and any director or officer of Penn West or of anySubsidiary of Penn West, including PWPL.

 

**Promoters**

** **

No person or company has been, within the twomost recently completed financial years or during the current financial year, a“promoter” (as defined in the *Securities Act*(Ontario)) of Penn West or of a Subsidiary of Penn West.

 

**AUDIT COMMITTEE DISCLOSURES**

** **

National Instrument 52-110 (“**NI 52-110**”) relating to audit committeeshas mandated certain disclosures for inclusion in this Annual InformationForm.  The text of the Audit Committee’smandate is attached as Appendix “B” to this Annual Information Form.

 

**Composition of the Audit Committee andRelevant Education and Experience**

** **

The members of the Audit Committee are JamesC. Smith, chairman, and James E. Allard, Shirley A. McClellan andFrank Potter, each of whom is independent and financially literate within themeaning of NI 52-110.  The followingcomprises a brief summary of each member’s education and experience that isrelevant to the performance of his responsibilities as an Audit Committeemember.

 

***JamesC. Smith (Chairman)***

*** ***

Mr. Smith is a Chartered Accountant with over 35 years ofexperience in public accounting and industry. Since 1998, he has been a business consultant and independent directorto a number of public and private companies operating in the oil and naturalgas industry.  From February 2002 toJune 2006, he served as the Vice-President and Chief Financial Officer ofMercury Energy Corporation, a private oil and natural gas company.  Mr. Smith also held the position ofChief Financial Officer of Segue Energy Corporation, a private oil and naturalgas company, from January 2001 to August 2003.  From 1999 to 2000, Mr. Smith was theVice-President and Chief Financial Officer of Probe Exploration Inc., apublicly traded oil and natural gas company. Mr. Smith served as the Vice-President and Chief Financial Officerof Crestar Energy Inc. from its inception in 1992 until 1998, during which timethe company completed an initial public offering, was listed on the TSX andcompleted several major debt and equity financing transactions.

 

***JamesE. Allard***

*** ***

Mr. Allard is an independent directorand business advisor.  He has a Bachelorof Science degree in Business Administration from the University of Connecticutand completed the Advanced Management Program at Harvard University.  Mr. Allard has focused his career oninternational finance in the petroleum industry for the past 40 years, duringwhich time he has served as the Chief Executive Officer, Chief FinancialOfficer and/or a director of a number of publicly traded and privatecompanies.  Over the past nine years hehas served on the board of the Alberta Securities Commission, acted as the soleexternal trustee and advisor to a mid-sized pension plan and served as adirector and advisor to several companies. From 1981 to 1995, Mr. Allard served as a senior executive officerof Amoco Corporation and as a director of Amoco Canada, which at that time wasCanada’s largest natural gas producer.

 

33

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***FrankPotter***

*** ***

Mr. Potter has a background in international banking in Europe, theMiddle East and the United States.  Hemanaged the international business of one of Canada’s principal banks beforebeing appointed Executive Director of the World Bank in Washington where heserved for nine years.  Mr. Pottersubsequently served as a Senior Advisor at the Department of Finance for theCanadian government.  He is currently theChairman of Emerging Markets Advisors, Inc., a Toronto based consultancythat assists corporations in making and managing direct investmentsinternationally.  Mr. Potter serveson a number of boards, including Canadian Tire Corporation, Limited, the RoyalOntario Museum and Softchoice Corporation.

 

***ShirleyA. McClellan***

*** ***

Mrs. McClellan is a Distinguished Scholar in Residence at theUniversity of Alberta for the Faculties of Agriculture and Rural Economy andthe School of Business.  She lecturesprimarily in Rural Economy and the School of Business.  Mrs. McClellan brings to Penn West theexperience gained over 20 years of distinguished service to the Province ofAlberta.  Her career included the officesof Deputy Premier of Alberta from 2001 to 2007, Minister of Finance of Albertafrom 2004 to 2007 and Chair of the Treasury Board and Vice-Chair of the Agendaand Priorities Committee of the Government of Alberta.  Mrs. McClellan served a total of sixterms as a Member of the Alberta Legislative Assembly representing theconstituency of Drumheller-Stettler. Over this time period, she held numerous other portfolios, includingMinister of Agriculture, Food and Rural Development, Minister of Internationaland Intergovernmental Relations, Minister of Community Development, andMinister of Health.

 

**Pre-Approval Policies and Procedures forNon-Audit Services**

** **

The terms of the engagement of Penn West’sexternal auditors to provide audit services, including the budgeted fees forsuch audit services and the representations and disclaimer relating thereto,must be pre-approved by the entire Audit Committee.

 

With respect to any engagements of PennWest’s external auditors for non-audit services, Penn West must obtain theapproval of the Audit Committee or the Chairman of the Audit Committee prior toretaining the external auditors to complete such engagement.  If such pre-approval is provided by theChairman of the Audit Committee, the Chairman shall report to the AuditCommittee on any non-audit service engagement pre-approved by him at the AuditCommittee’s first scheduled meeting following such pre-approval.

 

If, after using its reasonable best efforts,Penn West is unable to contact the Chairman of the Audit Committee on a timelybasis to obtain the pre-approval contemplated by the preceding paragraph, PennWest may obtain the required pre-approval from any other member of the AuditCommittee, provided that any such Audit Committee member shall report to theAudit Committee on any non-audit service engagement pre-approved by him at theAudit Committee’s first scheduled meeting following such pre-approval.

 

**External Auditor Service Fees**

** **

The following table summarizes the fees paidto KPMG LLP for external audit and other services during the periods indicated.

 
| **Year**   | ** ** | **Audit Fees(1)**** ****($)** | ** ** | **Audit Related Fees(2)**** ****($)** | ** ** | **Tax Fees(3)********($)** | ** ** | **All Other Fees(4)**** ****($)** | ** ** |
|------------|------------|-----------------------------------------|------------|------------------------------------------------------|------------|---------------------------------|------------|--------------------------------------------------|------------|
| ** ** | ** ** | ** **                              | ** ** | ** **                                           | ** ** | ** **                      | ** ** | ** **                                       | ** ** |
| 2008       |       | 1,550,000                               |       | 562,500                                              |       | 3,712                           |       | —                                           |       |
|       |       |                                    |       |                                                 |       |                            |       |                                             |       |
| 2007       |       | 1,045,000                               |       | 120,000                                              |       | 7,914                           |       | —                                           |       |

 

----

Notes:

 

(1)             The aggregate fees billed by our externalauditor in each of the last two fiscal years for audit services, includingSarbanes — Oxley compliance related services.

(2)             The aggregate fees billed in each of thelast two fiscal years by our external auditor for assurance and related servicesthat are reasonably related to the performance of the audit or review of ourfinancial statements (and not included in audit services fees in note(1)).  The services comprising the feesdisclosed under this category principally consisted of French translationservices and matters related to the corporate acquisitions completed in 2008.

 

34

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(3)             The aggregate fees billed in each of thelast two fiscal years by our external auditor for professional services for taxcompliance, tax advice and tax planning. The services comprising the fees disclosed under this categoryprincipally consisted of assistance and advice in relation to the communicationof the taxability of distributions to Unitholders.

(4)             The aggregate fees billed in each of thelast two fiscal years by our external auditor for products and services notincluded under the headings “Audit Fees”, “Audit Related Fees” and “Tax Fees”.

 

**Relianceon Exemptions**

** **

At no time since the commencement of Penn West’smost recently completed financial year has Penn West relied on any of theexemptions contained in Sections 2.4, 3.2, 3.4 or 3.5 of NI 52-110,or an exemption from NI 52-110, in whole or in part, granted under Part 8thereof.  In addition, at no time sincethe commencement of Penn West’s most recently completed financial year has PennWest relied upon the exemptions in Subsection 3.3(2) or Section 3.6of NI 52-110.  Furthermore, at notime since the commencement of Penn West’s most recently completed financialyear has Penn West relied upon Section 3.8 of NI 52-110.

 

**AuditCommittee Oversight**

** **

At no time since the commencement of PennWest’s most recently completed financial year has a recommendation of the AuditCommittee to nominate or compensate an external auditor not been adopted by theBoard of Directors of PWPL.

 

**DISTRIBUTIONS TO UNITHOLDERS**

** **

During the three most recently completedfinancial years, we have declared the following amount of cash distributionsper Trust Unit, each amount being paid in the following month:

 
| **Month** | ** ** | **2009  ($)** | ** ** | **2008  ($)** | ** ** | **2007  ($)** | ** ** | **2006  ($)** | ** ** |
|-----------|------------|---------------|------------|---------------|------------|---------------|------------|---------------|------------|
| January   |       | 0.23          |       | 0.34          |       | 0.34          |       | 0.31          |       |
| February  |       | 0.23          |       | 0.34          |       | 0.34          |       | 0.34          |       |
| March     |       | 0.23          |       | 0.34          |       | 0.34          |       | 0.34          |       |
| April     |       | —        |       | 0.34          |       | 0.34          |       | 0.34          |       |
| May       |       | —        |       | 0.34          |       | 0.34          |       | 0.34          |       |
| June      |       | —        |       | 0.34          |       | 0.34          |       | 0.34          |       |
| July      |       | —        |       | 0.34          |       | 0.34          |       | 0.34          |       |
| August    |       | —        |       | 0.34          |       | 0.34          |       | 0.34          |       |
| September |       | —        |       | 0.34          |       | 0.34          |       | 0.34          |       |
| October   |       | —        |       | 0.34          |       | 0.34          |       | 0.34          |       |
| November  |       | —        |       | 0.34          |       | 0.34          |       | 0.34          |       |
| December  |       | —        |       | 0.34          |       | 0.34          |       | 0.34          |       |
| **Total** |       | 0.69          |       | 4.08          |       | 4.08          |       | 4.05          |       |

 

35

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**On January 14,2009, we announced that in light of our intended 2009 capital expenditurelevels and the continuing weak commodity price environment, we had approved areduction to our monthly distribution to Unitholders from $0.34 per Trust Unitper month to $0.23 per Trust Unit per month for the next two months (subject tochanges in commodity prices, production levels and capital expenditures),commencing with the distribution payable on February 13, 2009 toUnitholders of record on January 30, 2009. On March 26, 2009, we subsequently announced that in light of ourrevised 2009 capital expenditure levels and the continuing weak commodity price**environment, theBoard of Directors had approved a further reduction to our monthly distributionto Unitholders from $0.23 per Trust Unit per month to $0.15 per Trust Unit permonth, subject to changes in commodity prices, production levels and capitalexpenditures, commencing with the distribution to be paid on May 15, 2009 toUnitholders of record on April 30, 2009.  Future distributions are subject to the discretion of the Board ofDirectors and may vary depending on, among other things, the current andanticipated commodity price environment, our production levels and the amountof capital expenditures that we make. Cash distributions to Unitholders are not assured or guaranteed.  See “Risk Factors”.

** **

**MARKET FOR SECURITIES**

** **

**Units**

** **

The Units are listed and traded on the TSXunder the symbol PWT.UN and on the NYSE under the symbol PWE.  The following tables set forth certaintrading information for our Units in 2008 as reported by the TSX and the NYSE.

 
| ** ** | ** ** | **TSX**                      | ** ** |
|------------|------------|------------------------------|------------|
| ** ** | ** ** | **Unit price ($)** | ** ** | **Unit price ($)** | ** ** | ** ** | ** ** |
| **Period** | ** ** | **High**                     | ** ** | **Low** | ** ** | **Volume** | ** ** |
|       |       |                         |       |   |   |   |   |
| January    |       | 28.04                        |       | 24.45 |   | 33,930,707 |   |
| February   |       | 29.44                        |       | 26.10 |   | 24,266,003 |   |
| March      |       | 29.20                        |       | 26.97 |   | 23,758,942 |   |
| April      |       | 32.01                        |       | 28.35 |   | 21,082,554 |   |
| May        |       | 34.95                        |       | 29.66 |   | 22,395,091 |   |
| June       |       | 35.60                        |       | 31.96 |   | 24,200,848 |   |
| July       |       | 34.71                        |       | 29.13 |   | 20,205,817 |   |
| August     |       | 31.25                        |       | 28.51 |   | 17,049,678 |   |
| September  |       | 30.40                        |       | 22.91 |   | 31,474,406 |   |
| October    |       | 25.50                        |       | 15.05 |   | 39,485,740 |   |
| November   |       | 21.87                        |       | 15.28 |   | 25,431,412 |   |
| December   |       | 17.55                        |       | 12.93 |   | 30,997,981 |   |

 
| ** ** | ** ** | **NYSE**                       | ** ** |
|------------|------------|--------------------------------|------------|
| ** ** | ** ** | **Unit price (US$)** | ** ** | **Unit price (US$)** | ** ** | ** ** | ** ** |
| **Period** | ** ** | **High**                       | ** ** | **Low** | ** ** | **Volume** | ** ** |
|       |       |                           |       |   |   |   |   |
| January    |       | 27.50                          |       | 23.52 |   | 45,787,618 |   |
| February   |       | 29.92                          |       | 25.99 |   | 34,885,928 |   |
| March      |       | 28.90                          |       | 26.30 |   | 35,437,097 |   |
| April      |       | 31.88                          |       | 27.60 |   | 37,202,450 |   |
| May        |       | 35.49                          |       | 29.10 |   | 45,269,580 |   |
| June       |       | 35.00                          |       | 31.50 |   | 38,923,000 |   |
| July       |       | 34.17                          |       | 28.92 |   | 47,463,628 |   |
| August     |       | 30.30                          |       | 26.62 |   | 33,681,348 |   |
| September  |       | 28.81                          |       | 22.00 |   | 64,983,228 |   |
| October    |       | 24.00                          |       | 13.00 |   | 123,125,280 |   |
| November   |       | 19.01                          |       | 11.86 |   | 64,281,100 |   |
| December   |       | 14.19                          |       | 9.97 |   | 77,151,448 |   |

 

36

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**Convertible Debentures Assumed Pursuant tothe Vault Acquisition**

** **

We assumed the 7.2% 2006 Debentures and the8% 2005 Debentures from Vault on January 10, 2008 in connection with theVault Acquisition.  The 7.2% 2006Debentures and the 8% 2005 Debentures began trading on the TSX as oursecurities on January 15, 2008 under the symbols “PWT.DB.E” and“PWT.DB.C”, respectively.

*** ***

***7.2%2006 Debentures***

*** ***

The following table sets forth certaintrading information for our 7.2% 2006 Debentures in 2008 as reported by the TSX(with each unit of volume traded being equal to $100 principal amount of 7.2%2006 Debentures).

 
| ** **           | ** ** | **TSX**                       | ** ** |
|----------------------|------------|-------------------------------|------------|
| ** **           | ** ** | **Debenture price  ($)** | ** ** | **Debenture price  ($)** | ** ** | ** ** | ** ** |
| **Period**           | ** ** | **High**                      | ** ** | **Low** | ** ** | **Volume** | ** ** |
|                 |       |                          |       |   |   |   |   |
| January (15-31) |       | 101.25                        |       | 100.29 |   | 60,120 |   |
| February             |       | 101.50                        |       | 100.76 |   | 21,740 |   |
| March                |       | 102.00                        |       | 100.65 |   | 5,190 |   |
| April                |       | 102.00                        |       | 100.50 |   | 3,840 |   |
| May                  |       | 102.00                        |       | 99.75 |   | 6,660 |   |
| June                 |       | 102.00                        |       | 101.00 |   | 16,300 |   |
| July                 |       | 101.75                        |       | 101.50 |   | 2,320 |   |
| August               |       | 102.95                        |       | 101.00 |   | 430 |   |
| September            |       | 102.00                        |       | 101.25 |   | 2,210 |   |
| October              |       | 99.50                         |       | 90.00 |   | 1,940 |   |
| November             |       | 95.00                         |       | 79.00 |   | 990 |   |
| December             |       | 90.00                         |       | 82.00 |   | 1,100 |   |

*** ***

***8% 2005Debentures***

*** ***

The following table sets forth certaintrading information for our 8% 2005 Debentures in 2008 as reported by the TSX(with each unit of volume traded being equal to $100 principal amount of 8%2005 Debentures).

 
| ** **           | ** ** | **TSX**                       | ** ** |
|----------------------|------------|-------------------------------|------------|
| ** **           | ** ** | **Debenture price  ($)** | ** ** | **Debenture price  ($)** | ** ** | ** ** | ** ** |
| **Period**           | ** ** | **High**                      | ** ** | **Low** | ** ** | **Volume** | ** ** |
|                 |       |                          |       |   |   |   |   |
| January (15-31) |       | —                        |       | — |   | — |   |
| February             |       | —                        |       | — |   | — |   |
| March                |       | 104.50                        |       | 104.50 |   | 300 |   |
| April                |       | —                        |       | — |   | — |   |
| May                  |       | —                        |       | — |   | — |   |
| June                 |       | 106.55                        |       | 104.00 |   | 1,480 |   |
| July                 |       | —                        |       | — |   | — |   |
| August               |       | 105.99                        |       | 105.99 |   | 100 |   |
| September            |       | 105.00                        |       | 104.03 |   | 5,490 |   |
| October              |       | 104.25                        |       | 104.25 |   | 100 |   |
| November             |       | —                        |       | — |   | — |   |
| December             |       | 100.00                        |       | 100.00 |   | 330 |   |

** **

**Convertible Debentures Assumed Pursuant tothe Canetic Acquisition**

** **

We assumed the 6.5% 2005 Debentures, the 6.5%2006 Debentures and the 8% 2004 Debentures from Canetic on January 11,2008 in connection with the completion of the Canetic Acquisition.  The 6.5% 2005 Debentures, the 6.5% 2006Debentures and the 8% 2004 Debentures began trading on the TSX as oursecurities on January 16, 2008 under the symbols

 

37

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“PWT.DB.D”, “PWT.DB.F” and “PWT.DB.B”,respectively.  We also assumed the 9.4%convertible unsecured subordinated debentures from Canetic on January 11,2008 in connection with the completion of the Canetic Acquisition; however,these debentures were subsequently repaid on July 31, 2008 when theymatured and are no longer outstanding.

*** ***

***6.5%2005 Debentures***

*** ***

The following table sets forth certaintrading information for our 6.5% 2005 Debentures in 2008 as reported by the TSX(with each unit of volume traded being equal to $100 principal amount of 6.5%2005 Debentures).

 
| ** **           | ** ** | **TSX**                       | ** ** |
|----------------------|------------|-------------------------------|------------|
| ** **           | ** ** | **Debenture price  ($)** | ** ** | **Debenture price  ($)** | ** ** | ** ** | ** ** |
| **Period**           | ** ** | **High**                      | ** ** | **Low** | ** ** | **Volume** | ** ** |
|                 |       |                          |       |   |   |   |   |
| January (16-31) |       | 100.00                        |       | 98.00 |   | 2,430 |   |
| February             |       | 101.00                        |       | 99.00 |   | 10,120 |   |
| March                |       | 104.80                        |       | 100.50 |   | 1,580 |   |
| April                |       | 102.25                        |       | 101.00 |   | 1,680 |   |
| May                  |       | 102.25                        |       | 101.10 |   | 10,760 |   |
| June                 |       | 104.00                        |       | 102.00 |   | 5,850 |   |
| July                 |       | 102.55                        |       | 100.00 |   | 4,340 |   |
| August               |       | 101.50                        |       | 100.00 |   | 5,460 |   |
| September            |       | 102.00                        |       | 100.00 |   | 3,410 |   |
| October              |       | 100.00                        |       | 90.00 |   | 3,720 |   |
| November             |       | 98.50                         |       | 92.00 |   | 2,470 |   |
| December             |       | 95.00                         |       | 90.00 |   | 970 |   |

*** ***

***6.5%2006 Debentures***

*** ***

The following table sets forth certaintrading information for our 6.5% 2006 Debentures in 2008 as reported by the TSX(with each unit of volume traded being equal to $100 principal amount of 6.5%2006 Debentures).

 
| ** **           | ** ** | **TSX**                       | ** ** |
|----------------------|------------|-------------------------------|------------|
| ** **           | ** ** | **Debenture price  ($)** | ** ** | **Debenture price  ($)** | ** ** | ** ** | ** ** |
| **Period**           | ** ** | **High**                      | ** ** | **Low** | ** ** | **Volume** | ** ** |
|                 |       |                          |       |   |   |   |   |
| January (16-31) |       | 99.50                         |       | 97.00 |   | 33,980 |   |
| February             |       | 101.00                        |       | 97.00 |   | 36,700 |   |
| March                |       | 101.00                        |       | 99.00 |   | 46,420 |   |
| April                |       | 100.80                        |       | 97.25 |   | 41,385 |   |
| May                  |       | 101.25                        |       | 98.50 |   | 25,180 |   |
| June                 |       | 102.50                        |       | 100.00 |   | 33,430 |   |
| July                 |       | 101.52                        |       | 100.50 |   | 25,950 |   |
| August               |       | 102.90                        |       | 95.00 |   | 47,040 |   |
| September            |       | 102.90                        |       | 98.50 |   | 27,790 |   |
| October              |       | 99.55                         |       | 69.00 |   | 27,530 |   |
| November             |       | 94.00                         |       | 75.00 |   | 99,830 |   |
| December             |       | 83.02                         |       | 73.00 |   | 44,200 |   |

*** ***

***8% 2004Debentures***

*** ***

The following table sets forth certaintrading information for our 8% 2004 Debentures in 2008 as reported by the TSX(with each unit of volume traded being equal to $100 principal amount of 8%2004 Debentures).

 

38

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| ** **           | ** ** | **TSX**                       | ** ** |
|----------------------|------------|-------------------------------|------------|
| ** **           | ** ** | **Debenture price  ($)** | ** ** | **Debenture price  ($)** | ** ** | ** ** | ** ** |
| **Period**           | ** ** | **High**                      | ** ** | **Low** | ** ** | **Volume** | ** ** |
|                 |       |                          |       |   |   |   |   |
| January (16-31) |       | 101.50                        |       | 101.00 |   | 640 |   |
| February             |       | 104.03                        |       | 103.72 |   | 680 |   |
| March                |       | —                        |       | — |   | — |   |
| April                |       | 105.12                        |       | 104.50 |   | 1,780 |   |
| May                  |       | 113.51                        |       | 104.39 |   | 1,050 |   |
| June                 |       | 116.68                        |       | 104.03 |   | 1,350 |   |
| July                 |       | 110.19                        |       | 104.01 |   | 820 |   |
| August               |       | 104.50                        |       | 104.50 |   | 30 |   |
| September            |       | 104.75                        |       | 103.55 |   | 390 |   |
| October              |       | 103.55                        |       | 70.00 |   | 1,440 |   |
| November             |       | 100.00                        |       | 97.00 |   | 1,950 |   |
| December             |       | 100.00                        |       | 97.01 |   | 2,390 |   |

 

PennWest does not have any classes of securities that are outstanding but that arenot listed or quoted on a market place. In addition, to Penn West’s knowledge, no securities of Penn West areheld in escrow, are subject to a pooling agreement, or are subject to a contractualrestriction on transfer (except in respect of pledges made to lenders).

 

**INDUSTRY CONDITIONS**

** **

The oil andnatural gas industry is subject to extensive controls and regulations governingits operations (including land tenure, exploration, development, production,refining, transportation, and marketing) imposed by legislation enacted byvarious levels of government and with respect to pricing and taxation of oiland natural gas by agreements among the governments of Canada, Alberta, BritishColumbia, and Saskatchewan, all of which should be carefully considered byinvestors in the oil and gas industry. It is not expected that any of these controls or regulations will affectour operations in a manner materially different than they would affect otheroil and gas companies of similar size. All current legislation is a matter of public record and we are unableto predict what additional legislation or amendments may be enacted.  Outlined below are some of the principalaspects of legislation, regulations and agreements governing the oil and gasindustry.

 

**Pricingand Marketing - Oil and Natural Gas**

** **

The producers ofoil are entitled to negotiate sales contracts directly with oil purchasers,with the result that the market determines the price of oil.  Oil prices are primarily based on worldwidesupply and demand.  The specific pricedepends in part on oil quality, prices of competing fuels, distance to market,the value of refined products, the supply/demand balance, and other contractualterms.  Oil exporters are also entitledto enter into export contracts with terms not exceeding one year in the case oflight crude oil and two years in the case of heavy crude oil, provided that anorder approving such export has been obtained from the National Energy Board ofCanada (the “**NEB**”).  Any oil export to be made pursuant to acontract of longer duration (to a maximum of 25 years) requires an exporter toobtain an export licence from the NEB and the issuance of such licence requiresa public hearing and the approval of the Governor in Council.

 

The price ofnatural gas is determined by negotiation between buyers and sellers.  Natural gas exported from Canada is subjectto regulation by the NEB and the Government of Canada.  Exporters are free to negotiate prices andother terms with purchasers, provided that the export contracts must continueto meet certain other criteria prescribed by the NEB and the Government ofCanada.  Natural gas (other than propane,butane and ethane) exports for a term of less than two years or for a term oftwo to 20 years (in quantities of not more than 30,000 m3/day), must be made pursuant to anNEB order.  Any natural gas export to bemade pursuant to a contract of longer duration (to a maximum of 25 years) or alarger quantity requires an exporter to obtain an export licence from the NEBand the issuance of such licence requires a public hearing and the approval ofthe Governor in Council.

 

The governmentsof Alberta, British Columbia, and Saskatchewan also regulate the volume of naturalgas that may be removed from those provinces for consumption elsewhere based onsuch factors as reserve availability, transportation arrangements, and marketconsiderations.

 

39

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** **

**PipelineCapacity**

** **

Although pipelineexpansions are ongoing, the lack of firm pipeline capacity continues to affectthe oil and natural gas industry from time to time by limiting the ability toproduce and to market oil and natural gas production.  In addition, the pro-rationing of capacity onthe inter-provincial pipeline systems from time to time also continues toaffect the ability to export oil and natural gas.

 

**TheNorth American Free Trade Agreement**

** **

The NorthAmerican Free Trade Agreement (“**NAFTA**”)among the governments of Canada, United States of America, and Mexico becameeffective on January 1, 1994.  NAFTAcarries forward most of the material energy terms that are contained in theCanada United States Free Trade Agreement. In the context of energy resources, Canada continues to remain free todetermine whether exports of energy resources to the United States or Mexicowill be allowed, provided that any export restrictions do not: (i) reducethe proportion of energy resources exported relative to domestic use (based uponthe proportion prevailing in the most recent 36 month period); (ii) imposean export price higher than the domestic price subject to an exception withrespect to certain voluntary measures which only restrict the volume ofexports; and (iii) disrupt normal channels of supply.  All three countries are prohibited fromimposing minimum or maximum export or import price requirements, provided, inthe case of export price requirements, any prohibition in any circumstances inwhich any other form of quantitative restriction is prohibited, and in the caseof import-price requirements, such requirements do not apply with respect toenforcement of countervailing and anti-dumping orders and undertakings.

 

NAFTAcontemplates the reduction of Mexican restrictive trade practices in the energysector by 2010 and prohibits discriminatory border restrictions and exporttaxes.  NAFTA also contemplates clearerdisciplines on regulators to ensure fair implementation of any regulatory changesand to minimize disruption of contractual arrangements and avoid undueinterference with pricing, marketing and distribution arrangements, which isimportant for Canadian natural gas exports.

 

**ProvincialRoyalties and Incentives**

** **

***General***

*** ***

In addition tofederal regulation, each province has legislation and regulations that governland tenure, royalties, production rates, environmental protection, and othermatters.  The royalty regime is asignificant factor in the profitability of crude oil, natural gas liquids,sulphur, and natural gas production. Royalties payable on production from lands other than Crown lands aredetermined by negotiation between the mineral freehold owner and the lessee,although production from such lands is subject to certain provincial taxes androyalties.  Crown royalties aredetermined by governmental regulation and are generally calculated as apercentage of the value of the gross production.  The rate of royalties payable generallydepends in part on prescribed reference prices, well productivity, geographicallocation, field discovery date, method of recovery, and the type or quality ofthe petroleum product produced.  Otherroyalties and royalty-like interests are, from time to time, carved out of theworking interest owner’s interest through non-public transactions.  These are often referred to as overridingroyalties, gross overriding royalties, net profits interests, or net carriedinterests.

 

Occasionally thegovernments of the western Canadian provinces create incentive programs forexploration and development.  Suchprograms often provide for royalty rate reductions, royalty holidays, and taxcredits, and are generally introduced when commodity prices are low.  The programs are designed to encourageexploration and development activity by improving earnings and cash flow withinthe industry.  Royalty holidays andreductions would reduce the amount of Crown royalties paid by oil and gasproducers to the provincial governments and would increase the net income andfunds from operations of such producers. However, the trend in recent years, in light of high commodity prices,has been for provincial governments to eliminate, amend or allow such incentiveprograms to expire without renewal.** **Recent actions taken by provincial governments (and in particular the Albertagovernment) in response to the quick and significant decrease in commodityprices signal that this trend has slowed and may be changing course (at leasttemporarily until commodity prices recover). See below for further details.

 

The Canadian federalcorporate income tax rate levied on taxable income is 19.5% effective January 1,2008 for active business income including resource income.  With the elimination of the corporate surtaxeffective January 1, 2008 and other rate reductions introduced in the October 2007Economic Statement and Notice of Ways and Means Motion, 2006 Federal 

 

40

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Budget, thefederal corporate income tax rate will decrease to 15% in four additionalsteps: 19% on January 1, 2009; 18% on January 1, 2010; 16.5% on January 1,2011; and 15% on January 1, 2012.

 

***Alberta***

*** ***

InAlberta, companies are granted the right to explore, produce and developpetroleum and natural gas resources in exchange for royalties, bonus bidpayments and rents.  On October 25,2007, the Government of Alberta released a report entitled “The New RoyaltyFramework” (the “**NRF**”) containingthe Government’s proposals for Alberta’s new royalty regime, which was followedby the Mines and Minerals (New Royalty Framework) Amendment Act, 2008, whichwas given Royal Assent on December 2, 2008.  The NRF and the applicable new legislationbecame effective on January 1, 2009. Prior to the NRF, the amount of royalties that were payable wasinfluenced by the oil production, density of the oil, and the vintage of theoil.  Originally, the vintage classifiedoil was “new oil” and “old oil” depending on when the oil pools werediscovered.  If the pool was discoveredprior to March 31, 1974 it was considered “old oil”, if it was discoveredafter March 31, 1974 and before September 1, 1992, it was considered“new oil”.  The Alberta Governmentintroduced in 1992 a Third Tier Royalty with a base rate of 10% and a rate capof 25% for oil pools discovered after September 1, 1992.  The new oil royalty reserved to the Crown hada base rate of 10% and a rate cap of 30%. The old oil royalty reserved to the Crown had a base rate of 10% and arate cap of 35%.  The NRF eliminates this classification andestablishes new royalty rates for conventional oil, natural gas and oilsands.  The new royalty rates forconventional oil are set by a single sliding rate formula which is appliedmonthly and increases the old royalty from 30% to 35% applied to the old and newtiers, to up to 50% and with rate caps once the price of conventional oilreaches $120 per barrel.  The slidingrate formula includes in its calculation the price of oil and well production.

 

Withrespect to natural gas, and similar to the conventional oil framework, theroyalties outlined in the NRF are set by a single sliding rate formula rangingfrom 5% to 50% with a rate cap once the price of natural gas reaches$16.59/GJ.  Prior to the NRF, the royaltyreserved to the Crown in respect of natural gas production, subject to variousincentives, was between 15% and 30%, in the case of new natural gas, andbetween 15% and 35%, in the case of old natural gas, depending upon aprescribed or corporate average reference price.  In response to the drop in commodity pricesexperienced during the second half of 2008, the Government of Alberta announcedon November 19, 2008, the introduction of a five year program oftransitional royalty rates with the intent of promoting new drilling.  Under this new program companies drilling newnatural gas or conventional oil deep wells (between 1,000 and 3,500 metres)will be given a one-time option, on a well by well basis, to adopt either thenew transitional royalty rates or those outlined in the NRF.  In order to qualify for this program wellsmust be drilled during the period starting on November 19, 2008 and endingon December 31, 2013.  Followingthis period all new wells drilled will automatically be subject to the NRF.

 

Oilsands projects are now subject to the NRF and are regulated by, among others,the *Oil Sands Royalty Regulation, 2009 OilSands Allowed Costs (Ministerial) Regulation* and the *Bitumen Valuation Methodology (Ministerial)Regulation, 2009*, all approved**bythe Government of Alberta on December 10, 2008.  The rates applicable to oil sands are between1% and 9% and are calculated depending on the price of oil.  The royalty payable is 1% when oil is pricedbelow or at $55 per barrel and it increases for every dollar over and abovethat price, to a maximum of 9% when oil is priced at $120 or higher.  The after payout net royalty starts at 25%and increases for every dollar when oil is priced above $55 up to 40% when oilis priced at $120 or higher.

 

On April 10,2008, the Government of Alberta introduced two new royalty programs that willencourage the development of deep oil and gas reserves: (a) a five-yearoil program for exploration wells over 2,000 metres that will provide royaltyadjustments to offset higher drilling costs and provide a greater incentive forproducers to continue to pursue new, deeper oil plays (these oil wells willqualify for up to a $1 million or 12 months of royalty offsets, whichever comesfirst); and (b) a five-year natural gas deep drilling program that willreplace the existing program in order to encourage continued deep gasexploration for wells deeper than 2,500 metres (the program will create asliding scale of royalty credit according to depth, of up to $3,750 permetre).  These new programs are beingimplemented along with the NRF.

 

Regulationsmade pursuant to the *Mines and Minerals Act*(Alberta) provided various incentives for exploring and developing oil reservesin Alberta.  However, the AlbertaGovernment announced in August of 2006 that four royalty programs were tobe amended, a new program was to be introduced and the Alberta Royalty TaxCredit Program was to be eliminated, effective January 1, 2007.  The programs affected by this announcementwere: (i) Deep Gas Royalty Holiday; (ii) Low Productivity WellRoyalty Reduction; (iii) Reactivated Well Royalty Exemption; and (iv) HorizontalRe-Entry Royalty Reduction.  The programintroduced was the Innovative Energy Technologies Program (the “**IETP**”), which has a stated 

 

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objectiveof promoting the producers’ investment in research, technology and innovationfor the purposes of improving environmental performance while creatingcommercial value.  The IETP providesroyalty reductions that are presumed to reduce financial risk.  Alberta Energy decides which projects qualifyand the level of support that will be provided. The deadline for the IETP’s final round of applications was September 20,2008.  The successful applicants for thefirst two rounds have been announced, and those for the third round selectionare scheduled to be announced in the first half of 2009.  The technical information gathered from thisprogram is to be made public once a two-year confidentiality period expires.

 

TheNRF includes a policy of “shallow rights reversion”.  The Government of Alberta started toimplement this policy on January 1, 2009, and its intent is to maximizethe development of currently undeveloped resources that is consistent with theGovernment of Alberta’s objective of maximizing recovery of known gasresources, while increasing royalty revenues. The policy’s stated objective is for the mineral rights to shallow gasgeological formations that are not being developed to revert back to theGovernment and be made available for resale, and in the event of non-productiveshallow wells, to sever the rights from shallow zones and encourage increasedproduction from up-hole zones.  Theshallow rights reversion policy affects all petroleum and natural gasagreements; however, the timing of the reversion will differ depending onwhether the leases and licenses were acquired prior to January 1, 2009 orsubsequent to January 1, 2009. Leases granted after January 1, 2009 will be subject to shallowrights reversion at the expiry of the primary term, and in the event of alicence the policy will apply at the expiry of the intermediate term.  Holders of leases or licences that have beencontinued indefinitely prior to January 1, 2009 will receive a noticeregarding the reversion of the shallow rights, which will be implemented threeyears from the date of the notice.  Thelease or licence holder can make a request to extend this period.  The order in which these agreements willreceive the reversion notice will depend on the vintage of their term, with theolder leases and licenses receiving a reversion notice first.  Leases or licences that were granted prior toJanuary 1, 2009 but have not yet been continued will have a grace perioduntil they are continued under section 15 of the *P&G Tenure Regulation* and will be subject to deeperrights reversion prior to receiving a shallow rights reversion notice.

 

On March 3,2009, the Government of Alberta announced a three-point incentive program tostimulate new and continued economic activity in Alberta.  The program includes a drilling royaltycredit for new conventional oil and natural gas wells and a new well royaltyincentive program.  Under the drillingroyalty credit program a $200 per meter royalty credit will be available on newconventional oil and natural gas wells drilled between April 1, 2009 and March 31,2010, subject to certain maximum amounts. The maximum credits available will be determined by a company’sproduction level in 2008 and its drilling activity between April 1, 2009and March 31, 2010.  Based on our2008 production we will be entitled to a maximum credit of approximately $30million of royalties payable during the period of April 1, 2009 to March 31,2010.  The new well royalty incentiveprogram will apply to wells that commence production of conventional oil andnatural gas between April 1, 2009 and March 31, 2010.  The program provides for a maximum 5% royaltyrate for the first 12 months of production, up to a maximum of 50,000 barrelsof oil or 500 MMcf of natural gas.

 

Thethree-point incentive program also includes an investment of $30 million by theGovernment of Alberta in abandonment and reclamation projects for orphanwells.  The stated objective of thisinvestment is to encourage the cleanup of inactive oil and gas wells and tostimulate new activity within the services sector.

 

***British Columbia***

*** ***

Producers of oiland natural gas in British Columbia are required to pay annual rental paymentswith respect to the Crown leases and royalties and freehold production taxes inrespect of oil and gas produced from Crown and freehold lands.  The amount payable as a royalty in respect ofoil depends on the type of oil, the value of the oil, the quantity of oilproduced in a month, and the vintage of the oil.  Generally, the vintage of oil is based on thedetermination of whether the oil is produced from a pool discovered before October 31,1975 (old oil), between October 31, 1975 and June 1, 1998 (new oil),or after June 1, 1998 (third-tier oil). The royalty rates are calculated in three stages, which take intoaccount the vintage of the oil, if the oil produced has already been sold andany royalty exempt value applicable (exempt wells).  Oil produced from newly discovered pools maybe exempt from the payment of a royalty for the first 36 months of productionor 11,450m3 produced, whichever comesfirst; and the royalties for third-tier oil are the lowest reflecting thehigher costs of exploration and extraction that the producers incur.  The royalty payable on natural gas isdetermined by a sliding scale based on a reference price, which is the greaterof the price obtained by the producer, and a prescribed minimum price.  However, when the reference price is belowthe select price (a parameter used in the royalty rate formula), the royalty rateis fixed.  As an incentive for the productionand marketing of natural gas, which may have been flared, natural gas producedin association with oil has a lower royalty than the royalty payable onnon-conservation gas.

 

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On May 30,2003, the Ministry of Energy and Mines for British Columbia announced an Oiland Gas Development Strategy for the Heartlands (“**Strategy**”).  TheStrategy is a comprehensive program to address road infrastructure, targetedroyalties and regulatory reduction, and British Columbia service sectoropportunities.  In addition, the Strategyis intended to result in economic and employment opportunities for communitiesin British Columbia’s heartlands.

 

Some of thefinancial incentives in the Strategy include:

 

·                  Royalty credits towards the construction, upgrading, and maintenanceof road infrastructure in support of resource exploration and development.  Funding will be contingent upon an equalcontribution from industry.  This programhas evolved over past years as a result of the Province’s stated objective toincrease competitiveness.  On March 2,2009, the Government of British Columbia announced the 2009 InfrastructureRoyalty Credit Program (“**Program**”),which allocates $120 million in royalty credits for oil and gas companies.  The Program provides access to royaltycredits to oil and gas companies with respect to certain approved roadconstruction or pipeline infrastructure projects intended to improve, or makepossible, the access to new and underdeveloped oil and gas areas.  Companies must apply to the Ministry ofEnergy and Mines for British Columbia prior to 2:00 p.m. on April 30,2009 to be considered for approval under the program.

 

·                  Changes to provincial royalties: new royalty rates for lowproductivity natural gas to enhance marginally economic resources plays,royalty credits for deep gas exploration to locate new sources of natural gas,and royalty credits for summer drilling to expand the drilling season.

 

TheBritish Columbia Energy Plan announced on February 27, 2007 outlines therequirements for the development of goals for conservation, energy efficiencyand clean energy.  In addition, itsstated goals include to promote competitiveness through the implementation of aNet Profit Royalty Program (“**NPRP**”)and facilitate the development of the oil and gas industry.  The NPRP’s objective is to share the capitalrisk of successful developments. Pursuant to the Net Profit Royalty Regulation, the holder of a lease canapply to pay monthly net profit royalties on production of oil and for naturalgas wells within a proposed project.  Theamount paid is calculated on the producer’s interest in the project, and itranges from 2% to 5% of the gross revenue and 15% to 35% of the net revenuesreceived.  In addition, it depends onwhich stage the well is at, which may be either pre-payout, after-payout oralready producing marketable gas.

 

TheGovernment of British Columbia has introduced a few more royalty programs, inaddition to the ones previously mentioned, including a royalty program for deepdiscovery wells, royalty programs with a stated goal of attracting investmentto less productive shallow gas wells (Ultra-Marginal Royalty Program), and theimplementation of royalty credits to assist the development of the coal-bed gasreserves found in the Province of British Columbia.

 

***Saskatchewan***

*** ***

In Saskatchewan,the amount payable as a royalty in respect of oil depends on the vintage of theoil, the type of oil, the quantity of oil produced in a month, and the value ofthe oil.  For Crown royalty and freeholdproduction tax purposes, crude oil is considered “heavy oil”, “southwestdesignated oil”, or “non-heavy oil other than southwest designated oil”.  The conventional royalty and production taxclassifications of oil production are applicable to each of the three crude oiltypes.  The Crown royalty and freeholdproduction tax structure for crude oil is price sensitive and varies betweenthe base royalty rates of 5% for all “fourth tier oil” to 20% for “oldoil”.  Marginal royalty rates are 30% forall “fourth tier oil” to 45% for “old oil”.

 

The amountpayable as a royalty in respect of natural gas is determined by a sliding scalebased on a reference price (which is the greater of the amount obtained by theproducer and a prescribed minimum price), the quantity produced in a givenmonth, the type of natural gas, and the vintage of the natural gas.  As an incentive for the production andmarketing of natural gas which may have been flared, the royalty rate onnatural gas produced in association with oil is less than on non-associatednatural gas.  The royalty and productiontax classifications of gas production are “fourth tier gas” introduced October 1,2002, “third tier gas”, “new gas”, and “old gas”.  The Crown royalty and freehold production taxfor gas is price sensitive and varies between the base royalty rate of 5% for“fourth tier gas” and 20% for “old gas”. The marginal royalty rates are between 30% for “fourth tier gas” and 45%for “old gas”.

 

On October 1,2002, the following changes were made to the royalty and tax regime inSaskatchewan:

 

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·                  A new Crown royalty and freehold production tax regime applicable toassociated natural gas (gas produced from oil wells) that is gathered for useor sale and is produced from: (a) oil wells with a finished drilling dateon or after October 1, 2002; and (b) oil wells with a finisheddrilling date prior to October 1, 2002, where the individual oil well hasa gas-oil production ratio in any month of more than 3,500 cubic metres of gasfor every cubic metre of oil.  Theroyalty/tax is payable on associated natural gas produced from an oil well thatexceeds approximately 65,000 cubic metres in a month.  The associated natural gas royalty/tax regimewill apply to gas produced from oil wells affected by concurrent productionapprovals after October 1, 2002 if the oil wells meet the criteria inparagraphs (a) or (b) above.

 

·                  A modified system of incentive volumes and maximum royalty/tax ratesapplicable to the initial production from oil wells and gas wells with afinished drilling date on or after October 1, 2002 was introduced.  The incentive volumes are applicable tovarious well types and are subject to a maximum royalty rate of 2.5% and afreehold production tax rate of zero percent.

 

·                  The elimination of the re-entry and short section horizontal oilwell royalty/tax categories.  Allhorizontal oil wells with a finished drilling date on or after October 1,2002 will receive the “fourth tier” royalty/ tax rates and new incentivevolumes.

 

·                  A horizontal oil well with a finished drilling date on or after October 1,2002 that is a non-deep oil well qualifies for a 6,000 cubic metre incentivevolume.

 

·                  A horizontal oil well with a finished drilling date on or after October 1,2002 that is a deep oil well qualifies for a 16,000 cubic metre incentivevolume.

 

In 1975, the Government of Saskatchewan introduced a Royalty Tax Rebate (“**RTR**”) as a response to the Government ofCanada disallowing crown royalties and similar taxes as a deductible business expense for income tax purposes.  As of January 1, 2007, the remaining balance of anyunused RTR will be limited in its carry forward to seven years since the Government of Canada’s initiative to reintroduce the fulldeduction of provincial resource royalties from federal and provincial taxable income.  Saskatchewan’s RTR will be wound down as aresult of the Government of Canada’s plan to reintroduce full deductibility ofprovincial resource royalties for corporate income tax purposes.

 

On June 19,2007, the Government of Saskatchewan introduced the Orphan Well and FacilityLiability Management Program pursuant to the amendment of the *Oil and Gas ConservationAct* and the *Oil and GasConservation Regulations*, 1985. The program includes a security deposit, which has two purposes: (i) preventingany person with insufficient financial capability from acquiring oil and gaswells or facilities; and (ii) in the case of a bankrupt company, the fundscover the decommissioning and reclaiming of orphan properties.  An additional change introduced is themandatory licensing of all upstream oil and gas facilities in Saskatchewan.

 

**LandTenure**

** **

Crude oil andnatural gas located in the western provinces is owned predominantly by therespective provincial governments. Provincial governments grant rights to explore for and produce oil andnatural gas pursuant to leases, licences, and permits for varying terms, theminimum of which is two years, and on conditions set forth in provinciallegislation including requirements to perform specific work or makepayments.  Oil and natural gas located insuch provinces can also be privately owned and rights to explore for andproduce such oil and natural gas are granted by lease on such terms andconditions as may be negotiated.

 

**EnvironmentalRegulation**

** **

The oil andnatural gas industry is subject to environmental regulations pursuant to avariety of provincial and federal legislation. Such legislation provides for restrictions and prohibitions on therelease or emission of various substances produced in association with certainoil and gas industry operations.  Inaddition, such legislation requires that well and facility sites be abandonedand reclaimed to the satisfaction of provincial authorities.  Compliance with such legislation can requiresignificant expenditures and a breach of such requirements may result insuspension or revocation of necessary licenses and authorizations, civilliability for pollution damage, and the imposition of material fines andpenalties.

 

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***Alberta***

 

Environmentallegislation in Alberta has been consolidated into the *Environmental Protection and Enhancement Act*(Alberta)(the “**EPEA**”), which came intoforce on September 1, 1993, and the *Oiland Gas Conservation Act*(Alberta) (the “**OGCA**”). The EPEA and OGCA impose stricter environmental standards, require morestringent compliance, reporting and monitoring obligations, and significantlyincreased penalties.  In 2006, theAlberta Government enacted regulations pursuant to the EPEA to specificallytarget sulphur oxide and nitrous oxide emissions from industrial operationsincluding the oil and gas industry.  In addition, the reduction emission guidelines outlined in the *Climate Change and Emissions Management Amendment Act*came into effect on July 1, 2007 (“**CCEMAA**”).  Under thislegislation, Alberta facilities emitting more than 100,000 tonnes of greenhousegases a year must reduce their emissions intensity by 12%.  Industries have three options to choose fromin order to meet the reduction requirements outlined in this legislation: (i) bymaking improvements to operations that result in reductions; (ii) bypurchasing emission credits from other sectors or facilities that haveemissions below the 100,000 tonne threshold and are voluntarily reducing theiremission; or (iii) by contributing to the Climate Change and EmissionsManagement Fund (the “**Fund**”).  Industries can either choose one of theseoptions or a combination thereof. Pursuant to CCEMAA and the *SpecifiedGas Emitters Regulation*, companies were obliged to reduce theiremission intensity by 12% by March 31, 2008.  Alberta industries have achieved 2.6 milliontonnes of actual reduction, due to changes in operations and investing onverified offset projects.  In addition,certain companies contributed $40 million to the Fund.  It is reasonably likely that the trend towardsstricter standards in environmental legislation and regulation will continue.

 

On January 24,2008, the Alberta Government announced a new climate change action plan thatwill cut Alberta’s projected 400 million tonnes of emissions in half by2050.  This plan focuses on three areas: (i) carboncapture and storage, which will be mandatory for *in situ* oil sand facilities that use heavy fuels for steamgeneration; (ii) energy conservation and efficiency; and (iii) greeningproduction through increased investment in clean energy technology, includingsupporting research on new oil sands extraction processes and funding projectsthat reduce the cost of separating carbon dioxide from other emissions.  In addition to thisaction plan, the Provincial Energy Strategy unveiled on December 11, 2008is expected to, among other things, support the upgrading, refining andpetrochemical clusters existing in the Province, market Alberta’s energyinternationally, review the emission targets and carbon charges applied tolarge facilities, and promote the innovation of energy technology byencouraging investment in research and development.

 

***British Columbia***

 

BritishColumbia’s Environmental Assessment Act became effective on June 30,1995.  This legislation rolls theprevious processes for the review of major energy projects into a singleenvironmental assessment process with public participation in the environmentalreview process.  On February 27,2007, the Government of British Columbia unveiled the Energy Plan outlining itsstrategy towards the environment, which includes targeting zero net greenhousegas emissions, promoting new investments in innovation, and becoming theworld’s leader in sustainable environmental management.  For this purpose, on December 18, 2007proposals were sought for applications to the Innovative Clean Energy Fund, inorder to attract new technologies that will help solve energy and environmentalissues.  With regards to the oil andnatural gas industry the objective is to achieve clean energy throughconservation and energy efficient practices, while competitiveness is advocatedin order to attract investment for the development of the oil and natural gassector.  Among the changes to beimplemented are: (i) a new Net Profit Royalty Program; (ii) thecreation of a Petroleum Registry; (iii) the establishment of aninfrastructure royalty program (combining roads and pipelines); (iv) theelimination of routine flaring at producing wells; (v) the creation ofpolicies and measures for the reduction of emissions; (vi) the developmentof unconventional resources such as tight gas and coalbed gas; and (vii) thenew Oil and Gas Technology Transfer Incentive Program that encourages theresearch, development and use of innovative technologies to increase recoveriesfrom existing reserves and promotes responsible development of new oil and gasreserves.  In furtherance of theseinitiatives, on July 1, 2008 the Government of British Columbia introducedrevenue-neutral carbon tax legislation that is applied to all fossil fuels usedin the Province of British Columbia.  Thetax would be phased in, and the initial rate would be based on CO2 equivalent of $10 pertonne for the first six months of 2009 and $15 per tonne for the last sixmonths of 2009, followed by $5 per tonne increases in July of every yearuntil 2012.  Tax credits and reductionswill be used in order to offset the tax revenues that the Government of BritishColumbia would receive otherwise.  On April 3,2008, the Government of British Columbia introduced the *GreenhouseGas Reduction (Cap and Trade) Act,* which will allow participation inthe Western Climate Initiative cap and trade system that is currently beingdeveloped.  The system establishes alimit on emissions and allows regulated emitters to buy/sell emissionallowances or offset emits.  The emitteris obliged to obtain emission allowances (compliance units) equal to the amountof 

 

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greenhouse gasesemitted within a certain period of time, and that are supposed to besurrendered to the Government of British Columbia as proof of compliance.

 

***Federal***

 

In December 2002,the Government of Canada ratified the Kyoto Protocol (“**Kyoto Protocol**”).  The Kyoto Protocol calls for Canada to reduceits greenhouse gas emissions to 6% below 1990 “business-as-usual” levelsbetween 2008 and 2012.  Given revisedestimates of Canada’s normal emissions levels, this target translates into anapproximately 40% gross reduction in Canada’s current emissions.  It is uncertain, based on the Updated ActionPlan announced by the Federal Government (see below), that the Kyoto Protocoltarget of 6% below 1990 emission levels will be enforced in Canada.  Bill C-288, which is intended to ensure thatCanada meets its global climate change obligations under the Kyoto Protocol,was passed by the House of Commons on February 14, 2007.  On April 26, 2007, the FederalGovernment released its Action Plan to Reduce Greenhouse Gases and AirPollution (the “**Action Plan**”)(also known as ecoACTION), which includes the regulatory framework for airemissions.  This Action Plan covers notonly large industry, but regulates the fuel efficiency of vehicles and thestrengthening of energy standards for a number of energy using products.

 

On January 31,2008, the Government of Canada and the Province of Alberta released the finalreport of the Canada-Alberta ecoENERGY Carbon Capture and Storage Task Force,which recommends, among others things: (i) incorporating carbon captureand storage into Canada’s clean air regulations; (ii) allocating newfunding into projects through competitive process; and (iii) targetingresearch to lower the cost of technology.

 

Inorder to strengthen the Action Plan, on March 10, 2008, the Government ofCanada released “Turning the Corner — Taking Action to Fight Climate Change”(the “**Updated Action Plan**”), whichprovides some additional guidance with respect to the Government’s plan toreduce greenhouse gas emissions by 20% by 2020 and by 60% to 70% by 2050.

 

TheUpdated Action Plan is primarily directed towards industrial emissions fromcertain specified industries, including the oil sands, oil and gas andrefining.  The Updated Action Plan isintended to create a carbon emissions trading market, including an offsetsystem, to provide an incentive to reduce greenhouse gas emissions andestablish a market price for carbon. There are mandatory reductions of 18% from the 2006 baseline starting in2010 and an additional 2% in subsequent years for existing facilities.  This target will be applied to regulatedsectors on a facility-specific, sector-wide or corporate basis.  In the case of oil sands production,petroleum refining, natural gas pipelines and upstream oil and gas the targetwill be considered facility-specific (sectors in which the facilities arecomplex and diverse, or where emissions are affected by factors beyond thecontrol of the facility operator). Emissions from new facilities, which are those built between 2004 and2011, will be based on a cleaner fuel standard to encourage continuousemissions intensity reductions over time, and will be granted a 3-year graceperiod during which no emissions intensity targets will apply.  Targets will begin to apply on the fourthyear of commercial operation and the baseline will be the third year’semissions intensity, with a 2% continuous annual emission intensity improvementrequired.  The definition of new facilityalso includes greenfield facilities, major expansions constituting more than a25% increase in a facility’s physical capacity, as well as transformations to afacility that involve significant changes to its processes.  For upstream oil and gas and natural gaspipelines, it will be applied using a sector-specific approach.  For the oil sands, its application will be process-specific:oil sands plants built in 2012 and later, those which use heavier hydrocarbons,up-graders and *in-situ*productionwill have mandatory standards in 2018 that will be based on carbon capture andstorage.

 

Inthe following regulated sectors, the Updated Action Plan will apply only tofacilities exceeding a minimum annual emissions threshold: (i) 50,000tonnes of CO2 equivalent per year for natural gas pipelines;(ii) 3,000 tonnes of CO2 equivalent per upstream oil and gas facility;and (iii) a 10,000 boe/d company. These proposed thresholds are significantly stricter than the currentAlberta regulatory threshold of 100,000 tonnes of CO2 equivalent per year per facility.

 

Fourseparate compliance mechanisms are provided in respect of the above targets:Technology Fund contributions, offset credits, clean development credits andcredits for early action.  The mostsignificant of these compliance mechanisms, at least initially, will be theTechnology Fund, to which regulated entities will be able to contribute inorder to comply with emissions intensity reductions.  The contribution rate will increase overtime, beginning at $15 per tonne for the 2010 to 2012 period, rising to $20 pertonne in 2013, and thereafter increasing at the nominal rate of gross domesticproduct growth.  Contribution limits willcorrespondingly decline from 70% in 2010 to 0% in 2018.  Monies raised through contributions to theTechnology Fund will be used to invest in technology to reduce greenhouse gasemissions.  Alternatively, regulatedentities may be able 

 

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toreceive credits for investing in large-scale and transformative projects at thesame contribution rate and under similar requirements as mentioned above.

 

Theoffset system is intended to encourage emissions reductions from activitiesoutside of the regulated sphere, allowing non-regulated entities to participatein and benefit from emissions reduction activities.  In order to generate offset credits, projectproponents must propose and receive approval for emissions reduction activitiesthat will be verified before offset credits will be issued to the projectproponent.  Those credits can then besold to regulated entities for use in compliance or non-regulated purchasersthat wish to either cancel the offset credits or bank them for future use orsale.

 

Underthe Updated Action Plan, regulated entities will also be able to purchasecredits created through the Clean Development Mechanism of the KyotoProtocol.  The purchase of such emissionsreduction credits will be restricted to 10% of each firm’s regulatoryobligation, with the added restriction that credits generated through forestsink projects will not be available for use in complying with the Canadianregulations.

 

Finally,a one-time credit of up to 15 metric tons worth of emissions credits will beawarded to regulated entities for emissions reduction activities undertakenbetween 1992 and 2006.  These creditswill be both tradable and bankable**.**

 

***Penn West and the Environment***

*** ***

We understand our responsibilities ofreducing the environmental impacts from our operations and recognize theinterests of other land users in resource development areas, and conduct ouroperations accordingly.  We are committedto reducing the environmental impact from our operations, and to involvingstakeholders throughout the exploration, development, production andabandonment process. Our environmental programs encompass resourceconservation, stakeholder communication and site abandonment/reclamation.  Our environmental programs are monitored toensure that they comply with all government environmental regulations and withour own environmental policies. The results of these programs are reviewed withour management and operations personnel.

 

Our Environmental Policy and EnvironmentalManagement Plan (“**EMP**”) encompassthe full range of air, water, soil and waste issues associated withexploration, development and production. The EMP includes guidelines to 11 keyareas that are considered in conjunction with oil and natural gas developmentplans. These guidelines help ensure safe and environmentally sound fieldoperations. The Environmental Operating Guidelines are used to train ouremployees in the practical and economic implementation of the EMP.

 

We maintain a program of detailedinspections, audits and field assessments to determine and quantify theenvironmental liabilities that will be incurred during the eventualdecommissioning and reclamation of our field facilities. We pursue a program ofenvironmental impact reduction aimed at minimizing these future corporateliabilities without hampering field productivity. This program, launched in1994****and ongoing into 2009, includes measures to remediate potentialcontaminant sources, reclaim spill sites and abandon unproductive wells andshut-in facilities. We have implemented strategies to reduce greenhouse gasemissions and flaring and continued the program to test CO2 enhanced oil recovery methods, whichwould “sequester” CO2 in hydrocarbon reservoirs.

 

Alberta and British Columbia are currentlythe only jurisdictions, in which we operate, that have passed legislationregarding greenhouse gas emissions.  Wedo not operate any facilities in Alberta that are regulated to reduce greenhouse gas (GHG) emissions.  However, wedo have minor working interests in five non-operated facilities that wererequired to meet the Alberta regulations. All of our fuel use in British Columbia is subject to a carbon tax basedon consumption.  The financialobligation, in both Alberta and British Columbia, is not material at this time.

 

Because the federal and provincial programsrelating to the regulation of the emission of greenhouse gases and other airpollutants continue to be developed, we are currently unable to predict thetotal impact of the potential regulations upon our business. Therefore, it ispossible that we could face increases in operating costs in order to complywith emissions legislation. However, in cooperation with the CanadianAssociation of Petroleum Producers, we will continue to work cooperatively withgovernments to develop an approach to deal with climate change issues thatprotects the industry’s competitiveness, limits the cost and administrativeburden of compliance and supports continued investment in the sector.  In the meantime, we will continue our currentactivities to reduce our emissions intensity, improve energy efficiency anddevelop CO2 injection and sequestration infrastructure.

 

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Penn West provides additional information ongreenhouse gases on our website and also participates in the annualinternational Carbon Disclosure Project. These two sources detail significantly more information regardingemissions, business strategy, governance, and potential risks for those who areinterested.

 

During 2008, wecontinued our pilot-scale CO2 injection program in the Pembinaarea and initiated a new CO2 injection pilot in the Swan Hills area.  If successful, the pilots could lead to amuch larger enhanced oil recovery program with potential to sequester significantvolumes of CO2. Also in 2008, we continued to participate in studies to develop a costeffective system to source large volumes of CO2 currently emitted within Alberta,and to transport it by pipeline for injection into producing oil fields in centralAlberta.

 

We are committed to meeting our responsibilities toprotect the environment wherever we operate and we anticipate making increasedexpenditures of both a capital and an expense nature as a result of theincreasingly stringent laws relating to the protection of the environment.  We will be taking such steps as required toensure continued compliance with applicable environmental legislation in eachjurisdiction in which we operate.  Webelieve that we are currently in material compliance with applicableenvironmental laws and regulations.  Wealso believe that it is reasonably likely that the trend towards stricterstandards in environmental legislation and regulation will continue.

 

**RISKFACTORS**

 

Thefollowing is a summary of certain risk factors relating to the business of PennWest and the Operating Entities.  Thefollowing information is a summary only of certain risk factors and isqualified in its entirety by reference to, and must be read in conjunctionwith, the detailed information appearing elsewhere in this Annual InformationForm.  Unitholders and potentialUnitholders should consider carefully the information contained herein and, inparticular, the following risk factors. If any of these risks occur, our production, revenues and financialcondition could be materially harmed, with a resulting decrease indistributions on, and the market price of, our Trust Units.

 

**Volatilityin oil and natural gas prices could have a material adverse effect on ourresults of operations and financial condition, which in turn could negativelyaffect the amount of distributions paid to our Unitholders.**

** **

Ourresults of operations and financial condition are dependent upon the pricesthat we receive for the oil and natural gas that we sell.  Historically, the oil and natural gas marketshave been volatile and are likely to continue to be volatile in thefuture.  Oil and natural gas prices havefluctuated widely during recent years and are subject to fluctuations inresponse to relatively minor changes in supply, demand, market uncertainty andother factors that are beyond our control. These factors include, but are not limited to:

 

·               globalenergy policy, including the ability of OPEC to set and maintain productionlevels and influence prices for oil;

·               politicalinstability and hostilities and the risk of hostilities;

·               foreignsupply of oil and natural gas, including liquefied natural gas;

·               weatherconditions;

·               theoverall level of energy demand;

·               productionand storage levels of natural gas;

·               governmentregulations and taxes;

·               currencyexchange rates;

·               theavailability of transportation infrastructure;

·               theeffect of worldwide environmental and/or energy conservation measures;

·               theprice and availability of alternative energy supplies; and

·               theoverall economic environment.

 

Anydecline in the price of oil or natural gas could have a material adverse effecton our operations, financial condition, borrowing ability, reserves and thelevel of expenditures for the development of reserves.  Fluctuations in the price of oil and naturalgas will also have an effect on the acquisition costs of any future oil andnatural gas properties that we may acquire. In addition, cash distributions paid to Unitholders are highly sensitiveto the prevailing price of crude oil and natural gas and may decline with anydecline in the price of oil or natural gas.

 

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**The price of oil and natural gas isaffected by political events throughout the world.  Any such event could result in a materialdecline in prices and result in a reduction of the funds flow available fordistribution to Unitholders.**

** **

The marketability and price of oil andnatural gas that may be acquired or discovered by us is and will continue to beaffected by political events throughout the world that cause disruptions in thesupply of oil.  Conflicts, or converselypeaceful developments, arising in the Middle East, and other areas of theworld, have a significant impact on the price of oil and natural gas.  Any particular event could result in amaterial decline in prices and therefore result in a reduction of our revenueand consequently the funds flow available for distribution to Unitholders.

 

**In addition, our oil and natural gas properties, wells and facilitiescould be subject to a terrorist attack. If any of our properties, wells or facilities are the subject of aterrorist attack it could have a material adverse effect on us.  We do not currently have insurance in respectof our Canadian operations to protect against the risk of terrorism.**

** **

**The ongoing global financial crisis has had(and may continue to have) an adverse effect on commodity prices and has had(and may continue to have) an adverse effect on our access to capital, one orboth of which could have a material adverse effect on our results of operationsand financial condition, which in turn could negatively affect the amount ofdistributions paid to our Unitholders.**

** **

Recent market events and conditions,including disruptions in the international credit markets and other financialsystems and the deterioration of global economic conditions, have causedsignificant volatility to commodity prices. These conditions worsened in 2008 and are continuing in 2009, causing aloss of confidence in the broader U.S. and global credit and financial marketsand resulting in the collapse of, and government intervention in, major banks,financial institutions and insurers and creating a climate of greatervolatility, less liquidity, widening of credit spreads, a lack of pricetransparency, increased credit losses and tighter credit conditions.  Notwithstanding various actions taken bygovernments, concerns about the general condition of the capital markets,financial instruments, banks, investment banks, insurers and other financialinstitutions caused the broader credit markets to further deteriorate and stockmarkets to decline substantially.  Thesefactors have negatively impacted company valuations and are expected to impactthe performance of the global economy going forward.

 

Petroleum prices are expected to remainvolatile for the near future as a result of market uncertainties over thesupply and demand of these commodities due to the current state of the worldeconomies, OPEC actions and the ongoing global credit and liquidity concerns.

 

As a result of the weakened global economicsituation, we (and all other oil and gas entities) expect to have restrictedaccess to capital and increased borrowing costs for the foreseeablefuture.  Although our business and assetbase have not changed materially, the lending capacity of all financialinstitutions has diminished and risk premiums have increased.  As future capital expenditures will befinanced out of cash generated from operations, borrowings and possible futureequity sales, our ability to do so is dependent on, among other factors, theoverall state of capital markets and investor appetite for investments in theenergy industry and our securities in particular.

 

To the extent that external sources ofcapital become limited or unavailable or available on onerous terms, ourability to make capital investments and maintain existing assets may be impaired,and our assets, liabilities, business, financial condition, results ofoperations and distributions may be materially and adversely affected as aresult.

 

**At December 31, 2008, we had approximately $1.4 billion of unusedcredit available under our credit facilities. Based on current funds available and expected cash from operations, webelieve that we have sufficient funds available to fund our projected capitalexpenditures.  However, if cash flow fromoperations is lower than expected or capital costs for these projects exceedscurrent estimates, or if we incur major unanticipated expenses related todevelopment or maintenance of our existing properties, we may be required toseek additional capital to maintain our capital expenditures at planned levels.  Failure to obtain any financing necessary forour capital expenditure plans may result in a delay in development orproduction on our properties and/or a decrease in distributions.**

 

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**We may not be able to repay all or part of our indebtedness, oralternatively refinance all or part of our indebtedness on commerciallyreasonable terms.  We may not be able tocomply with the covenants (and in particular the financial covenants) containedin our debt instruments.  The occurrenceof any one of these events could have a material adverse effect on our resultsof operations and financial condition, which in turn could negatively affectthe amount of distributions paid to our Unitholders.**

 

We currently have credit facilities in placethat have an aggregate borrowing limit of $4.0 billion and a maturity date of January 11,2011.  As of December 31, 2008,approximately $2.6 billion was outstanding under our creditfacilities.  The credit facilities arecomprised of two tranches which each revolve until their respective maturitydates.  Tranche one of our creditfacilities has an aggregate borrowing limit of $3.25 billion and is extendiblewith lender approval.  We have the rightto request an extension of the maturity date under tranche one such that theterm to maturity does not exceed three years.** **Tranche two of our creditfacilities has an aggregate borrowing limit of $750 million and isnon-extendible.  In the event thattranche one of our credit facilities is not extended before January 11,2011, all outstanding indebtedness under our credit facilities will berepayable at that date.  There is also arisk that our credit facilities will not be renewed for the same principalamount or on the same terms.  Any ofthese events could adversely affect our ability to fund our ongoing operationsand, as repayment of such indebtedness has priority over the payment of cashdistributions to Unitholders, to distribute cash to Unitholders.

 

We also currently have: (i) U.S.$475million principal amount of 2007 Senior Notes outstanding which requireprincipal repayments starting in May 2015 and continuing until May 2022;(ii) U.S.$480 million and Cdn$30 million principal amount of 2008 SeniorNotes outstanding which require principal repayments starting in May 2016and continuing until May 2020; (iii) £57 million principal amount of2008 Pounds Sterling Senior Notes outstanding which require principal repaymentin July 2018; and (iv) $296 million principal amount of ConvertibleDebentures outstanding which require principal repayments starting in August 2009and continuing until December 2011. In the event we are unable to repay or refinance these debt obligationsit may adversely affect our ability to fund our ongoing operations and, asrepayment of such indebtedness has priority over the payment of cashdistributions to Unitholders, to distribute cash to Unitholders.

 

We arerequired to comply with covenants under our credit facilities, the 2007 SeniorNotes, the 2008 Senior Notes and the 2008 Pounds Sterling Senior Notes.  In the event that we do not comply withcovenants under one or more of these debt instruments, our access to capitalcould be restricted or repayment could be required, which could adverselyaffect our ability to fund our ongoing operations and, as repayment of suchindebtedness has priority over the payment of cash distributions toUnitholders, to distribute cash to Unitholders.

 

**We may be unable to successfully competewith other companies in our industry, which could negatively affect the marketprice of our Trust Units and distributions to our Unitholders.**

** **

There is strong competition relating to allaspects of the oil and gas industry.  Wecompete with numerous other trusts and conventional exploration and productioncompanies for, among other things:

 

·               capital;

·               the acquisition of properties with longer life reserves andproperties with exploitation and development opportunities; and

·               access to equipment, refining capacity, drilling and service rigsand processing facilities.

 

The SIFT Tax imposed by the Government ofCanada is expected by us to make our Trust Units less attractive asconsideration for acquisitions.  As aresult of such increasing competition, we expect that it will become moredifficult to acquire producing assets and reserves on accretive terms.  We also compete for skilled industrypersonnel with a substantial number of other oil and gas companies and trusts.

 

**We will require additional financing fromtime to time, which may result in Unitholders suffering dilution.  If we are unable to obtain additionalfinancing at all or on reasonable terms, the amount of funds flow available fordistribution to Unitholders will be reduced.**

** **

In the normal course of making capitalinvestments to maintain and expand our oil and gas reserves, additional TrustUnits may be issued which may result in a decline in production per Trust Unitand reserves per Trust Unit. Additionally, from 

 

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time to time, we may issue Trust Units fromtreasury in order to reduce debt and maintain a more optimal capitalstructure.  Conversely, to the extentthat external sources of capital, including the issuance of additional TrustUnits, becomes limited or unavailable, our ability to make the necessarycapital investments to maintain or expand our oil and gas reserves will beimpaired.  We believe that the SIFT Taximposed by the Government of Canada will substantially eliminate thecompetitive advantage that we and other energy trusts have enjoyed relative toour industry competitors in raising capital in a tax-efficient manner.  To the extent that we are required to useadditional funds flow to finance capital expenditures or property acquisitionsor to pay debt service charges or to reduce debt, the amount of funds flow availablefor distribution to Unitholders will be reduced.

 

**Our hedging program could result in us notrealizing the full benefit of oil and natural gas price increases.**

** **

We may manage the risk associated withchanges in commodity prices by entering into oil or natural gas pricehedges.  If we hedge our commodity priceexposure, we could forego the benefits we would otherwise experience ifcommodity prices increase.  In addition, commodityhedging activities could expose us to cash and income losses.  To the extent that we engage in riskmanagement activities, there are credit risks associated with counterpartieswith which we contract.

 

**Being a limited purpose trustmakes us largely dependent upon the operations and assets of the OperatingEntities.  If the oil and natural gasreserves associated with the Operating Entities’ resource properties are notsupplemented through additional development activities or the acquisition ofoil and natural gas properties, the ability of the Operating Entities to continueto generate funds flow from operations for distribution to Unitholders maybecome adversely affected.**

 

We are entirely dependent upon the operationsand assets of the Operating Entities through our ownership, directly andindirectly, of securities of the Operating Entities, including the commonshares of PWPL, the Internal Notes and the NPIs.  Accordingly, our ability to pay cashdistributions to Unitholders are dependent upon the ability of the OperatingEntities to meet their interest, principal, dividend and other distributionobligations on the securities of the Operating Entities and the NPIs.  The Operating Entities’ income is receivedfrom the production of oil and natural gas from the Operating Entities’ resourceproperties and is susceptible to the risks and uncertainties associated withthe oil and natural gas industry generally.

 

**If we are unable to acquire additionalreserves, the value of our Trust Units and distributions to Unitholders willdecline.**

** **

Distributions of income from our properties,absent commodity price increases or cost effective exploration, acquisition anddevelopment activities, will decline over time in a manner consistent withdeclining production from typical oil, natural gas and natural gas liquidsreserves.  As we distribute a portion ofour funds flow to Unitholders, we do not reinvest funds flow in the same manneras some non-trust industry participants and we only conduct limited exploratoryactivities.  Accordingly, absent equity capitalinjections or increased debt levels, our production levels and reserves willdecline over time and, absent changes to other factors such as increases incommodity prices, the level of income available for distributions will alsodecline over time.

 

Our future oil and natural gas reserves andproduction, and therefore our funds flow, will be highly dependent on oursuccess in exploring and exploiting our reserves and land base and acquiringadditional reserves.  Without reserveadditions through acquisition, exploration or development activities, ourreserves and production will decline over time as our existing reserves aredepleted.

 

To the extent that external sources ofcapital, including the issuance of additional Trust Units, become limited orunavailable, our ability to make the necessary capital investments to maintainor expand our oil and natural gas reserves may be impaired.  To the extent that we are required to usehigher proportions of funds flow to finance capital expenditures or propertyacquisitions, the level of funds flow available for distributions will bereduced.

 

There can be no assurance that we will besuccessful in developing or acquiring additional reserves on terms that meetour investment objectives.

 

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**Fluctuations in foreign currency exchangerates and interest rates could adversely affect our business, and adverselyaffect the market price of our Trust Units and distributions to ourUnitholders.**

** **

World oil prices are based on United Statesdollars and the Canadian dollar price received by Canadian producers istherefore affected by the Canadian/U.S. dollar exchange rate, which fluctuatesover time.  In recent years, the Canadiandollar has increased materially in value against the United States dollar andhas at times traded above par against the United States dollar (although theCanadian dollar has recently declined sharply against the United Statesdollar).  Any such material increases inthe value of the Canadian dollar negatively affect our production revenues.  Any future strengthening of the Canadiandollar against the United States dollar could negatively affect the fundsavailable for future distributions and the future value of our reserves asdetermined by independent evaluators.

 

An increase in interest rates could result ina significant increase in the amount we pay to service debt, resulting in adecrease in distributions to Unitholders, which would negatively impact themarket price of the Trust Units.

 

**Actual reserves will vary from reservesestimates and those variations could be material, and negatively affect themarket price of our Trust Units and distributions to our Unitholders.**

** **

There are numerous uncertainties inherent inestimating quantities of oil, natural gas and natural gas liquid reserves andresources and funds flows to be derived therefrom, including many factorsbeyond our control.  The reserve andassociated funds flow information set forth herein represents estimates only.  In general, estimates of economicallyrecoverable oil and natural gas reserves and resources and the future net fundsflows therefrom are based upon a number of variable factors and assumptions,such as:

 

·               historical production from the properties;

·               production rates;

·               ultimate reserve recovery;

·               timing and amount of capital expenditures;

·               marketability of oil and natural gas;

·               royalty rates;

·               the assumed effects of regulation by governmental agencies; and

·               future operating costs;

 

all of which may vary from actualresults.  As a result, estimates of theeconomically recoverable oil and natural gas reserves or estimates of resourcesattributable to any particular group of properties, classification of suchreserves based on risk of recovery and estimates of future net revenuesexpected therefrom prepared by different engineers, or by the same engineers atdifferent times, may vary.  Our actualproduction, revenues and development and operating expenditures will vary fromreserve and resource estimates thereof and such variations could be material.

 

Estimates of proved reserves that may bedeveloped and produced in the future are sometimes based upon volumetriccalculations and upon analogy to similar types of reserves rather than actualproduction history.  Estimates based onthese methods are generally less reliable than those based on actual productionhistory.  Subsequent evaluation of thesame reserves based upon production history and production practices willresult in variations in the estimated reserves and such variations could bematerial.

 

In accordance with applicable securitieslaws, GLJ and Sproule have used forecast price and cost estimates incalculating reserve quantities included herein. Actual future net funds flows will be affected by other factorsincluding but not limited to actual production levels, supply and demand foroil and natural gas, curtailments or increases in consumption by oil and naturalgas purchasers, changes in governmental regulation or taxation and the impactof inflation on costs.

 

Actual production and funds flows derivedfrom reserves will vary from the reserve estimates contained in the engineeringreports summarized herein, and such variations could be material.  The engineering reports summarized herein arebased in part on the assumption that certain activities will be undertaken byus in future years and the further assumption that such activities will besuccessful.  The reserves and estimatedfunds flows to be derived therefrom contained in the engineering reportssummarized herein will be reduced, in future years, to the extent that suchactivities are not undertaken or, if undertaken, do not achieve the level ofsuccess assumed in the engineering reports summarized herein.

 

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**Our operation of oil and natural gas wells,and our participation in oil and natural gas wells operated by others, couldsubject us to environmental claims and liability and/or increased compliancecosts, all of which could affect the market price of our Trust Units and reducedistributions to Unitholders.**

** **

All phases of the oil and natural gasbusiness present environmental risks and hazards and are subject toenvironmental regulation pursuant to a variety of federal, provincial and locallaws and regulations.  Environmentallegislation provides for, among other things, restrictions and prohibitions onspills, releases or emissions of various substances produced in associationwith oil and natural gas operations.  Thelegislation also requires that wells, pipelines and associated facility sitesbe operated, maintained, abandoned and reclaimed to the satisfaction ofapplicable regulatory authorities. Compliance with such legislation can require significant expendituresand a breach may result in the imposition of fines and penalties, some of whichmay be material.  Environmentallegislation is evolving in a manner expected to result in stricter standardsand enforcement, larger fines and legal liability, and potentially increasedcapital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soilor water may give rise to liabilities to governments and third parties and mayrequire our Operating Entities to incur costs to remedy such discharge.  Furthermore, we believe the political climateappears to favour new programs for environmental laws and regulation,particularly in relation to the reduction of emissions.  Any such programs, laws or regulations, ifproposed and enacted, may contain emission reduction targets that we cannotmeet, and financial penalties or charges could be incurred as a result of thefailure to meet such targets.

 

In particular, there is uncertainty regardingthe Kyoto Protocol, the federal government’s Clean Air Act of 2006, the federalgovernment’s Action Plan to Reduce Greenhouse Gases and Air Pollution announcedon April 26, 2007 (the “**Action Plan**”)and the federal government’s update to the Action Plan announced on March 10,2008 (the “**Updated Action Plan**”).  The Clean Air Act proposes to reducegreenhouse gas emissions and other contaminants; however, emission targets andcompliance deadlines differ from those outlined in the Kyoto Protocol which wasratified by Canada.  The Action Plan(also known as ecoACTION) includes the regulatory framework for airemissions.  The Updated Action Planprovides additional guidance with respect to the federal government plan toreduce greenhouse gas emissions by 20% by 2020 and by 60% to 70% by 2050.  The Updated Action Plan is primarily directedtowards industrial emissions from certain specified industries including theoil sands, oil and gas and refining industries. If passed, the Clean Air Act, the Action Plan and the Updated ActionPlan may have adverse operational and financial implications to us.  Provincial emission reduction requirements,such as those contained in Alberta’s Climate Change and Emissions ManagementAct, in addition to the plan announced by the Alberta government on January 24,2008, may require the reduction of emissions or emissions intensity of ouroperations and facilities.  The direct orindirect costs of these regulations may adversely and materially affect ourbusiness.  No assurance can be given thatenvironmental laws will not result in a curtailment of production or a materialincrease in the costs of production, development or exploration activities orotherwise adversely affect our financial condition, results of operations orprospects.  Future changes in otherenvironmental legislation could occur and result in stricter standards ofenforcement, larger fines and liability, and increased capital expenditures andoperating costs, which could have a material adverse effect on our financialcondition or results of operations.  See“Industry Conditions — Environmental Regulation” herein.

 

Given the evolving nature of the debaterelated to climate change and the control of greenhouse gases and resultingrequirements, it is not currently possible to predict either the nature ofthose requirements or the impact on us and our operations and financialcondition.

 

**We depend upon our management and other keypersonnel and the loss of one or more of such individuals could negativelyaffect our business.**

** **

Unitholders depend upon the management ofPWPL in respect of the administration and management of all matters relating toour operations.  The success of ouroperations depends largely upon the skills and expertise of our seniormanagement and other key personnel.  Ourcontinued success depends upon our ability to retain and recruit suchpersonnel.  Investors who are not willingto rely on the management of PWPL should not invest in our securities.

 

**Our strategy in the current economic and industry environmentmay subject us to certain risks.**

 

Inlight of the current economic and commodity price environment, we have reducedour planned 2009 capital expenditures and our monthly distribution toUnitholders significantly from 2008 levels, in each case in an effort to minimizefurther increases in debt levels and position ourselves to capitalize onacquisition opportunities. There are certain risks associated with thisstrategy, including that: (i) reduced capital spending will decreasefuture production and cash flow 

 

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availablefor distributions; (ii) reducing cash distributions to Unitholders mayreduce the trading price or value of the Trust Units in the market; and (iii) wemay not be able to execute an attractive acquisition.  In addition, if the current commodity price environmentcontinues, we may be required to further revise our strategy, and any furtherchanges may adversely affect the cash distributions to Unitholders or the valueor trading price of the Trust Units.

 

**Distributions on our Trust Units are variable and may bereduced or suspended entirely.**

 

Theactual cash flow available for distribution to Unitholders is dependent on theamount of cash flow paid to the Trust by its Operating Entities and can varysignificantly from period to period for a number of reasons, including amongother things: (i) the Operating Entities’ operational and financialperformance (including fluctuations in the quantity of their oil, NGLs andnatural gas production and the sales price that they realize for suchproduction (after hedging contract receipts and payments)); (ii) fluctuationsin the costs to produce oil, NGLs and natural gas, including royalty burdens,and to administer and manage the Trust and its subsidiaries; (iii) theamount of cash required or retained for debt service or repayment; (iv) amountsrequired to fund capital expenditures and working capital requirements; and (v) foreigncurrency exchange rates and interest rates. Certain of these amounts are, inpart, subject to the discretion of the Board of Directors, which regularlyevaluates the Trust’s distribution payout with respect to anticipated cashflows, debt levels, capital expenditures plans and amounts to be retained tofund acquisitions and expenditures. In addition, our level of distribution perTrust Unit will be affected by the number of outstanding Trust Units and othersecurities that may be entitled to receive cash distributions, such as anyexchangeable shares that our Subsidiaries may issue from time to time. *Distributions may be increased, reduced or suspendedentirely depending on our operations and the performance of our assets. Themarket value of the Trust Units may deteriorate if the Trust is unable to meetdistribution expectations in the future, and that deterioration may bematerial.*

 

**The Government of Canada has enacted taxlaw changes that will tax our distributions and therefore reduce the percentageof our funds flow from operations that is available for distribution toUnitholders beginning in 2011 (or in certain circumstances, earlier than 2011).**

** **

On October 31, 2006, the FederalMinister of Finance proposed the SIFT Tax, which would deny the deduction ofdistributions at the trust level and subject any income of certain publiclytraded mutual fund trusts to tax at rates comparable to the combined federaland provincial corporate tax and to treat such distributions as taxabledividends to the unitholders.  On December 21,2006, the Federal Minister of Finance released draft legislation to implementthe SIFT Tax pursuant to which, commencing January 1, 2011 (provided weonly experience “normal growth” and no “undue expansion” before then) certaindistributions from us which would have otherwise been taxed as ordinary incomegenerally will be characterized as dividends to our Unitholders and will besubject to tax at the corporate rates at the trust level.  On June 22, 2007, the legislationreceived Royal assent.  Theimplementation of the SIFT Tax is expected to result in adverse tax consequencesto us and certain Unitholders (including most particularly Unitholders that aretax deferred or non-residents of Canada) and may impact the level of cashdistributions from us.

 

We believe that the SIFT Tax has reduced, andmay further reduce, the value of our Trust Units, which would be expected toincrease our cost of raising capital in the public capital markets.  In addition, we believe that the SIFT Tax: (a) hassubstantially eliminated any competitive advantage that we and other Canadianenergy trusts have enjoyed relative to our corporate peers in raising capitalin a tax-efficient manner; and (b) may place us and other Canadian energytrusts at a competitive disadvantage relative to certain of our industrycompetitors.  The SIFT Tax may also makethe Trust Units less attractive as consideration for acquisitions in thefuture.  As a result, it may become moredifficult for us to compete effectively for acquisition opportunities.

 

TheTrust is a taxable entity under the Tax Act and is taxable only on income thatis not distributed or distributable to the Unitholders.  As the Trust distributes all of its taxableincome to the Unitholders pursuant to the Trust Indenture and currentlysatisfies the requirements of the Tax Act applicable to the Trust, the Trustdoes not expect to pay income taxes until the earlier of January 1, 2011or if and when it ceases to be a trust. The SIFT Tax will not impose a tax on distributions from entities, suchas the Trust, until January 1, 2011 as long as that the Trust experiencesonly “normal growth” as set out in the guidelines described below.  Commencing in January 2011, the Trustwill be liable for tax on all distributions of income paid or payable toUnitholders, which distributions the Trust will no longer be able to deduct incomputing its taxable income.  The Trustcurrently has significant tax pools and expects to continue to increase its taxpool base until 2011.  Accordingly, it isexpected that the Trust will be able to shelter income for a period of timeafter the application of the SIFT Tax.

 

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The SIFT Tax provides that, while there is nointention to prevent “normal growth” during the transitional period, any “undueexpansion” would result in the transition period being terminated with the lossof the benefit to us of that transitional period.  As a result, the adverse tax consequencesresulting from the SIFT Tax could be borne sooner than January 1,2011.  On December 15, 2006, theDepartment of Finance issued guidelines with respect to what is meant by“normal growth” in this context. Specifically, the Department of Finance stated that “normal growth”would include equity growth within certain “safe harbour” limits, measured byreference to a SIFT’s marketcapitalization as of the end of trading on October 31, 2006 (which wouldinclude only the market value of the SIFT’s issued and outstandingpublicly-traded trust units, and not any convertible debt, options or otherinterests convertible into or exchangeable for trust units).  Thosesafe harbour limits are 40% for the period from November 1, 2006 to December 31,2007, and 20% each for calendar year 2008, 2009 and 2010.  Moreover, these limits are cumulative, sothat any unused limit for a period carries over into the subsequent period.  Additional details of the Department ofFinance’s guidelines include the following: (i) new equity for thesepurposes includes units and debt that is convertible into units (and mayinclude other substitutes for equity if attempts are made to develop those);and (ii) replacing debt that was outstanding as of October 31, 2006with new equity, whether by a conversion into trust units of convertibledebentures or otherwise, will not be considered growth for these purposes andwill therefore not affect the safe harbour.

 

On December 4, 2008, the FederalMinister of Finance announced changes to the guidelines discussed above toallow a SIFT to accelerate the utilization of the SIFT annual safe harbouramount for each of 2009 and 2010 so that the safe harbour amounts for 2009 and2010 are available on and after December 4, 2008.  This change does not alter the maximumpermitted expansion threshold for a SIFT, but it allows a SIFT to use itsnormal growth room remaining as of December 4, 2008 in a single year,rather than staging a portion of the normal growth room over the 2009 and 2010years.

 

The Department of Finance has indicated thatthe issuance of trust units by a SIFT as consideration in connection with theacquisition of, or the merger with, another SIFT, will not be considered growthfor these purposes and will therefore not affect a SIFT’s safe harbour.  Therefore, our issuance of Trust Units inconnection with the acquisition of Canetic and Vault is not considered growthfor these purposes and did not affect our safe harbour.

 

The Department of Finance has also indicatedthat a SIFT’s market capitalization for the purpose of calculating a SIFT’s“safe harbour” equity growth limit is equal to the aggregate market capitalizationof the SIFT and all SIFTs acquired by such SIFT as of the end of trading on October 31,2006.  The combined market capitalizationof the Trust, Canetic and Vault as of the close of trading on October 31,2006, having regard only to the issued and outstanding publicly-traded TrustUnits and Canetic and Vault trust units at such date, was approximately $15billion.  We believe that, as at March 25, 2009, our remaining combined “safeharbour” equity growth amount for the period ending December 31, 2010 isapproximately $14****billion (not including equity,including convertible debentures, issued to replace debt that was outstandingon October 31, 2006).  Theseguidelines may adversely affect the cost of raising capital and our ability toundertake significant acquisitions.  *Although the SIFT Tax is not expected to effect theTrust until 2011, the Trust could become subject to the trust-level tax soonerif it experiences growth other than “normal growth” before then.*

 

Currently, the SIFT Tax rules provide thatthe SIFT Tax rate will be the federal general corporate income tax rate (whichis anticipated to be 16.5% in 2011 and 15% in 2012) plus the provincial SIFTtax rate discussed below.

 

Pursuant to proposed regulationsto the Tax Act, the provincial SIFT Tax rate will be based on the generalprovincial corporate income tax rate in each province in which the Trust has apermanent establishment.  For purposes ofcalculating this component of the tax, the general corporate taxable incomeallocation formula will be used. Specifically, the Trust’s taxable distributions, if any, will beallocated to provinces by taking half of the aggregate of:

 

·                  that proportion of the Trust’s taxable distributions, if any, forthe year that the Trust’s wages and salaries in the province are of its totalwages and salaries in Canada; and

 

·                  that proportion of the Trust’s taxable distributions, if any, forthe year that the Trust’s gross revenues in the province are of its total grossrevenues in Canada.

 

It isanticipated that the Trust would be considered to have a permanentestablishment in Alberta only, where the provincial tax rate in 2011 isexpected to be 10%, which will result in an effective tax rate of 26.5% in2011.  Taxable distributions, if any,that are not allocated to any province, would instead be subject to a 10% rateconstituting the provincial component.

 

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On July 14, 2008,the Federal Minister of Finance announced proposed amendments to the Tax Act,including technical amendments to clarify certain aspects of the SIFT Tax andto provide rules to facilitate the conversion of existing SIFTs intocorporations on a tax-deferred basis (the “**ConversionRules**”).  The Conversion Rules addressmany of the principal substantive and administrative issues that arise whenstructuring a corporate conversion of an income trust under the Tax Act. TheConversion Rules contemplate two alternatives for the conversion of apublicly-traded SIFT into a taxable Canadian corporation and the winding-up ofthe SIFT’s underlying structure.  Thefirst alternative involves the winding-up of the SIFT into a taxable Canadiancorporation whereas the second approach involves the distribution by thepublicly-traded SIFT of shares of an underlying taxable Canadian corporation toits unitholders.  The Conversion Rules willgenerally only apply to the winding-up of a SIFT or a distribution of sharescompleted after July 14, 2008 and before 2013.  Bill C-10, whichreceived Royal Assent on March 12, 2009, contained legislationimplementing the Conversion Rules.

 

*The long term effect of theSIFT Tax on us cannot be determined at this time, but may be materially adverseto us and some or all of our Unitholders. There can be no assurance that we will be able to generate sufficienttax pools and/or reorganize our legal and tax structure in order to mitigate,in whole or in part, the expected impact of the SIFT Tax.*

 

For additional information, see “GeneralDevelopment of the Business — History and Development — Year Ended December 31,2006 — Changes to Taxation of Income Trusts”.

 

**It is probable that we will convert to a corporation or otherform of entity prior to January 1, 2013. The conversion may adversely impact some or all of our Unitholders.  In addition, we will be subject to additionalrisk factors that are relevant to the form of entity in to which we convert.**

 

As aresult of the above-described changes to the taxation of income trusts, theTrust may convert from an income trust structure to a corporate or other formof entity, prior to the Trust becoming subject to the SIFT Tax for thefinancial year beginning January 1, 2011. We are currently hesitant tomake structural changes prior to the end of 2010 unless opportunities arise, aswe believe this exemption period has value for our Unitholders. Even if we donot convert to a corporation or other form of entity prior to January 1, 2011,it is likely that such a conversion would be completed prior to January 1, 2013in order to effect the conversion without undue tax consequences for Penn Westor its Unitholders. As discussed in more detail above, Bill C-10, whichreceived Royal Assent on March 12, 2009, contained legislation implementing theSIFT Conversion Rules which facilitate the conversion of existing SIFTs intocorporations on a tax-deferred basis. Unless circumstances change within thecurrent capital markets or the regulatory, tax or political environment, wecurrently believe that we will most likely convert into a dividend payingcorporation. However, we are keeping our options open at this time and cannotprovide any assurances in this regard. If we do complete a conversion to acorporate or other form of structure, the nature of a Unitholder’s investmentwill change, and although at this time we believe that such a conversion may becompleted without creating a taxable event for most Unitholders for Canadianand U.S. federal income tax purposes, no assurance can be given that such aconversion will not give rise to income tax liability. However, going forward,there can be no assurance that the taxation of future payments received from usin a corporate or other form will not give rise to tax consequences that aremore adverse to securityholders than the current treatment of distributions to ourUnitholders, and may differ depending on the Unitholder’s tax jurisdiction andwhether the Unitholder is holding its investment in a taxable or tax-deferredaccount.

 

After 2010, the most important variables that will determine the levelof cash taxes incurred by us in a given year will be the price of crude oil andnatural gas, capital spending and the amount of tax pools available to us. Withthe current forward prices for commodity prices and our current plans withrespect to production, costs and capital spending, we do not expect asignificant change to our overall tax costs until at least 2014, even if wewere to convert to a corporation during 2010. Even after 2014, we expect thatour capital spending will help shelter taxes and would expect cash taxes toaverage approximately 10% to 12%of cash flow, which is not dissimilar to other oil and gas productioncompanies. However, if crude oil and natural gas prices were to strengthenbeyond the levels anticipated by the current forward market, our tax poolswould be utilized more quickly and we may experience higher than expected cashtaxes or payment of such taxes in an earlier time period. Moreover, we emphasizethat it is difficult to give guidance on future taxability as we operate withinan industry where various factors constantly change our outlook, includingfactors such as acquisitions, divestments, capital spending levels,distribution levels and commodity price changes.

 

**The new Alberta royalty regime may adversely impact us andour operations and reserves.**

 

In December 2008, the Government of Alberta passed into law a “NewRoyalty Framework”, effective January 1, 2009. The Government of Albertahas offered oil and gas producers a one-time option to select, for a five yearperiod, transitional royalty rates as an alternative to the New RoyaltyFramework in respect of certain new wells spud on or after November 19,2008. Additionally, on March 3, 2009, the Government of Alberta announceda short-term incentive program to encourage the drilling of new wells over thenext twelve months, which includes lower initial royalty rates and certainroyalty credits. See “Industry Conditions — Provincial Royalties andIncentives - Alberta” and “General Development of the Business — 

 

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History andDevelopment — Year Ended December 31, 2008 — Revisions to Alberta RoyaltyRegime”. In 2008,approximately 55% of our crude oil and natural gas production was from AlbertaCrown leases. Given that we have not yet completed a fiscal period operatingunder the New Royalty Framework and the fact that the New Royalty Framework issensitive to commodity price and production levels, it is not possible at thistime to determine the full impact of the New Royalty Framework (including thetransitional royalty rates and short-term incentives) on our financialcondition and operations, and in particular the extent to which the New RoyaltyFramework could reduce our cash flow, which could in turn reduce the cashotherwise available for distribution by us to our Unitholders. Our reserves andthe estimated future net revenue associated therewith, as contained in thereserve reports summarized in this Annual Information Form, reflect the revisedroyalty rates contemplated by the New Royalty Framework. Any adverse impact onus from the New Royalty Framework will be particularly felt in periods of highto mid-level commodity prices.

 

**We may not be able to achieve theanticipated benefits of acquisitions and the integration of acquisitions mayresult in the loss of key employees and the disruption of on-going businessrelationships.**

** **

We make acquisitions and dispositions ofbusinesses and assets in the ordinary course of business.  Achieving the benefits of acquisitionsdepends in part on successfully consolidating functions and integratingoperations and procedures in a timely and efficient manner, as well as ourability to realize the anticipated growth opportunities and synergies fromcombining the acquired businesses and operations with ours.  The integration of acquired businesses mayrequire substantial management effort, time and resources and may divertmanagement’s focus from other strategic opportunities and operational matters,and may also result in the loss of key employees, the disruption of on-goingbusiness, supplier, customer and employee relationships and reportabledeficiencies in internal controls over financial reporting or informationtechnology general controls.  Wecontinually assess the value and contribution of services provided and assetsrequired to provide such services.  Inthis regard, non-core assets are periodically disposed of, so that we can focusour efforts and resources more efficiently. Depending on the state of the market for such non-core assets, certainof our non-core assets, if disposed of, could be expected to realize less thantheir carrying value in our financial statements.

 

**The incorrect assessment of value at thetime of acquisitions could adversely affect the value of our Trust Units anddistributions to our Unitholders.**

** **

Acquisitions of oil and gas properties orcompanies will be based in large part on engineering and economic assessmentsmade by independent engineers.  Theseassessments include a series of assumptions regarding such factors as recoverabilityand marketability of oil and gas, future prices of oil and gas and operatingcosts, future capital expenditures and royalties and other government levieswhich will be imposed over the producing life of the reserves.  Many of these factors are subject to changeand are beyond our control.  All suchassessments involve a measure of geological and engineering uncertainty thatcould result in lower production and reserves than anticipated.  If actual reserves or production are lessthan we expect, our funds flow from operations and distributions to Unitholderscould be negatively affected.

 

**Our inability to manage growth couldadversely affect our business and our Unitholders.**

** **

We may be subject to growth related risks,including capacity constraints and pressure on our internal systems andcontrols.  Our ability to manage growtheffectively will require us to continue to implement and improve ouroperational and financial systems and to expand, train and manage our employeebase.  Our inability to deal with thisgrowth could have a material adverse impact on our business, operations andprospects.

 

**Changes in Canadian income tax legislationand other laws may adversely affect us and our Unitholders.**

** **

Income tax laws, or other laws or governmentincentive programs relating to the oil and gas industry, such as the treatmentof mutual fund trusts and resource taxation, may in the future be changed orinterpreted in a manner that adversely affects us and our Unitholders.  Furthermore, tax authorities havingjurisdiction over us or our Unitholders may disagree with how we calculate ourincome for tax purposes or could change administrative practises to ourdetriment or the detriment of our Unitholders.

 

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**Our indebtedness may limit the amount ofdistributions that we are able to pay to our Unitholders, and if we default onour debt, the net proceeds of any foreclosure sale would be allocated to therepayment of our lenders and other creditors and only the remainder, if any,would be available for distribution to our Unitholders.**

** **

Amounts paid in respect of interest andprincipal on debt we have incurred will reduce funds available fordistributions.  Variations in interestrates and any scheduled principal repayments could result in significantchanges in the amount required to be applied to debt service before payment ofthe NPIs.  Certain covenants in theagreements with our lenders may also limit distributions in certaincircumstances.  Increases in interestrates could also result in decreases to the market value of our TrustUnits.  Although we believe our creditfacilities and other debt instruments will be sufficient for our immediaterequirements, there can be no assurance that the amount will be adequate forour future financial obligations or that additional funds will be able to beobtained.

 

Our current credit agreement and other debtinstruments are unsecured and we must comply with certain financial debtcovenants.  The lenders and other debtholders could, in the future, require security over a portion of orsubstantially all of our assets.  Shouldthis occur, in the event that we become unable to pay our debt service chargesor otherwise commit an event of default such as bankruptcy, the lender andother debt holders may foreclose on or require us to sell our oil and gas andother assets.

 

**Changes in the regulation of the oil andgas industry may adversely affect our business.**

** **

Oil and natural gas operations (includingexploration, production, pricing, marketing and transportation operations) aresubject to extensive controls and regulations imposed by various levels ofgovernment that may be changed or amended from time to time.  We have no control over these changes andamendments and the impact that they may have on us, and any such impact couldbe material and adverse.  See “IndustryConditions” herein, including in respect of the Government of Alberta’s NRF andrelated shallow rights reversion program.

 

Our operations require licenses from variousgovernmental authorities.  There can beno assurance that we will be able to obtain all necessary licenses and permitsthat may be required to carry out exploration and development at our projects.

 

**Acquiring, developing and exploring for oiland natural gas involves many risks. Losses resulting from the occurrence of one or more of these risks mayadversely affect our business and thus the value of our Trust Units anddistributions to our Unitholders.**

** **

Acquiring, developing and exploring for oiland natural gas involves many risks, which even a combination of experience,knowledge and careful evaluation may not be able to overcome.  These risks include, but are not limited to:

 

·               encounteringunexpected formations or pressures;

·               premature declines of reservoirs;

·               blow-outs, equipment failures and other accidents;

·               sour gas releases;

·               uncontrollable flows of oil, natural gas or well fluids;

·               adverse weather conditions; and

·               pollution and other environmental risks, such as fires and spills.

 

Although we maintain insurance in accordancewith customary industry practice based on our projected cost benefit analysisof maintaining such insurance, we are not fully insured against all of theserisks.  Losses resulting from theoccurrence of these risks could have a material adverse impact on us.  Like other oil and natural gas trusts andcompanies, we attempt to conduct our business and financial affairs so as toprotect against political and economic risks applicable to operations in thejurisdictions where we operate but there can be no assurance that we will besuccessful in so protecting our assets.

 

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**We do not operate all of our properties andfacilities.  Therefore, our results ofoperations may be adversely affected by the failure of third party operators,and harm to their business could cause delays and additional expenses in receivingour revenues, which could adversely affect the market price of our Trust Unitsand distributions to our Unitholders.**

** **

Continuing production from a property, and tosome extent the marketing of production therefrom, largely depend upon theability of the operator of the property or related facilities.  Operating costs on most properties haveincreased over recent years.  To theextent the operator fails to perform these functions properly, operating incomewill be reduced.  Payments fromproduction generally flow through the operator and there is a risk of delay andadditional expense in receiving such revenues if the operator becomesinsolvent.

 

**An unforeseen defect in the chain of titleto our oil and natural gas producing properties may arise to defeat our claim,which could have an adverse affect on the market price of our Trust Units andcould reduce distributions to our Unitholders.**

** **

Although title reviews may be conducted priorto the purchase of oil and natural gas producing properties or the commencementof drilling wells, such reviews do not guarantee or certify that an unforeseendefect in the chain of title will not arise to defeat our claim, which couldresult in a reduction of the revenue received by us and consequently the fundsflow available for distribution to Unitholders.

 

**The termination or expiration of licensesand leases through which we or our industry partners hold our interests inpetroleum and natural gas substances could adversely affect the market price ofour Trust Units and distributions to our Unitholders.**

** **

Our properties are held in the form oflicenses and leases and working interests in licenses and leases.  If we or the holder of the license or leasefail to meet the specific requirement of a license or lease, the license orlease may terminate or expire.  There canbe no assurance that all of the obligations required to maintain each licenseor lease will be met.  The termination orexpiration of a license or lease or the working interest relating to a licenseor lease may have a material adverse effect on our results of operations andbusiness.

 

**We are exposed to potential liabilitiesthat may not be covered, in part or in whole, by insurance.**

** **

Our involvement in the exploration anddevelopment of oil and natural gas properties could subject us to liability forpollution, blowouts, property damage, personal injury or other hazards.  Prior to commencing operations, we obtaininsurance in accordance with industry standards to address certain of these risks.  Such insurance has limitations on liabilitythat may not be sufficient to cover the full extent of such liabilities.  In addition, such risks may not, in allcircumstances, be insurable or, in certain circumstances, we may elect not toobtain insurance to deal with specific risks due to the high premiumsassociated with such insurance or other reasons.  The payment of such uninsured liabilitieswould reduce the funds available to us. The occurrence of a significant event that we are not fully insuredagainst, or the insolvency of the insurer of such event, could have a materialadverse effect on our financial position, results of operations or prospectsand will reduce funds flow otherwise distributable by us.

 

**Distributions might be reduced duringperiods in which we make capital expenditures using our funds flow fromoperations, which could negatively affect the market price of our Trust Units.**

** **

Future oil and natural gas reserves and hencerevenues are highly dependent on our success in exploiting existing propertiesand acquiring additional reserves.  Wealso intend to distribute approximately 60% to 70% of our net funds flow toUnitholders rather than reinvesting it in reserve additions and productiongrowth or maintenance.  Accordingly, ifexternal sources of capital, including the issuance of additional Trust Units,become limited or unavailable on commercially reasonable terms, our ability tomake the necessary capital investments to maintain or expand our oil andnatural gas reserves will be impaired. To the extent that we are required to use funds flow to finance capitalexpenditures or property acquisitions, the level of funds flow available fordistribution to Unitholders will be reduced. Additionally, we cannot guarantee that we will be successful inexploring for and developing additional reserves or acquiring additionalreserves on terms that meet our investment objectives.  Without these reserve additions, our reserveswill decline and as a consequence,

 

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either production from, or the averagereserve life of, our properties will decline. Either decline may result in a reduction in the value of our Trust Unitsand in a reduction in cash available for distributions to Unitholders.

 

**Delays in business operations could adverselyaffect distributions to Unitholders and the market price of the Trust Units.**

** **

In addition to the usual delays in payment bypurchasers of oil and natural gas to the operators of the properties, and bythe operator to us, payments between any of such parties may also be delayed byrestrictions imposed by lenders, delays in the sale or delivery of products,delays in the connection of wells to a gathering system, blowouts or otheraccidents, recovery by the operator of expenses incurred in the operation ofproperties or the establishment by the operator of reserves for such expenses.

 

**We may in the future expand our operationsinto new geographical regions where our existing management does not haveexperience.  In addition, we may in thefuture acquire new types of energy related assets in respect of which ourexisting management does not have experience. Any such expansion or acquisition could result in our exposure to newrisks that if not properly managed could ultimately have an adverse effect onour business, the market price of our Trust Units and distributions to ourUnitholders.**

** **

The operations and expertise of ourmanagement are currently focused on oil and gas production and exploration anddevelopment in the Western Canadian Sedimentary Basin and, since the completionof the Canetic Acquisition, in North Dakota, Montana and Wyoming in the UnitedStates.  In the future, we may acquireoil and gas properties outside these geographic areas.  In addition, the Trust Indenture does notlimit our activities to oil and gas production and development, and we couldacquire other energy related assets, such as additional oil and natural gasprocessing plants, upgraders or pipelines. Expansion of our activities into new areas may present new additionalrisks or alternatively, significantly increase the exposure to one or more ofthe present risk factors that may result in our future operational andfinancial conditions being adversely affected.

 

**Non-Residents of Canada may be subject toadditional taxation by Canadian or foreign governments that may adverselyaffect them.**

** **

The Tax Act and the tax treaties betweenCanada and other countries may impose additional withholding or other taxes onthe cash distributions or other property paid by us to Unitholders who areNon-Residents of Canada, and these taxes may change from time to time.  Since January 1, 2005, a 15% Canadianwithholding tax is applied to any return of capital portion of distributionsmade to Non-Resident Unitholders.

 

Additionally, the reduced “QualifiedDividend” rate of 15% tax which has applied to our distributions under currentU.S. tax laws is scheduled to expire at the end of 2010 and there is noassurance that this reduced tax rate will be renewed by the U.S. government atsuch time.

 

Furthermore, it is anticipated that theimplementation of the SIFT Tax may have tax consequences for Non-Residents ofCanada that are more adverse than the tax consequences to other classes ofUnitholders.

 

**Your rights as a Unitholder differ from therights associated with other types of investments.**

** **

The Trust Units do not represent atraditional investment in the oil and natural gas sector and should not beviewed by investors as shares in PWPL. The Trust Units represent a fractional interest in our assets.  As holders of Trust Units, Unitholders willnot have the statutory rights normally associated with ownership of shares of acorporation including, for example, the right to bring “oppression” or“derivative” actions.  The rights ofUnitholders are specifically set forth in the Trust Indenture.  In addition, trusts are not defined asrecognized entities within the definitions of legislation such as the *Bankruptcy and Insolvency Act* (Canada),the *Companies’ Creditors Arrangement Act*(Canada) and in some cases the *Winding Upand Restructuring Act* (Canada). As a result, in the event of an insolvency or restructuring, aUnitholder’s position as such may be quite different than that of a shareholderof a corporation.  Our sole assets arethe NPIs and other investments in securities of our Operating Entities,including the Internal Notes.  The priceper Trust Unit is a function of anticipated income available for distributions,the oil and gas assets acquired by us and our ability to effect long-termgrowth in the value of our assets.  Themarket price of the Trust Units is sensitive to a variety of market conditionsincluding, but not 

 

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limited to, interest rates and our ability toacquire suitable oil and natural gas properties.  Changes in market conditions may adverselyaffect the trading price of the Trust Units.

 

The Trust Units are not “deposits” within themeaning of the *Canada Deposit InsuranceCorporation Act* (Canada) and are not insured under the provisions ofthat Act or any other legislation. Furthermore, we are not a trust company and, accordingly, we are notregistered under any trust and loan company legislation as we do not carry onor intend to carry on the business of a trust company.

 

**The limited liability of Unitholders isuncertain.**

** **

The Trust Indenture provides that noUnitholder will be subject to any liability in connection with our obligationsand affairs and, in the event that a court determines Unitholders are subjectto any such liabilities, the liabilities will be enforceable only against, andwill be satisfied only out of, our assets. Pursuant to the Trust Indenture, we will indemnify and hold harmlesseach Unitholder from any costs, damages, liabilities, expenses, charges andlosses suffered by a Unitholder resulting from or arising out of suchUnitholder not having such limited liability.

 

The Trust Indenture provides that all writteninstruments signed by or on our behalf must contain a provision to the effectthat such obligation will not be binding upon Unitholders personally.  Personal liability may also arise in respectof claims against us that do not arise under contracts, including claims intort, claims for taxes and possibly certain other statutory liabilities.  The possibility of any personal liability ofthis nature arising is considered unlikely. The *Income Trusts Liability Act*(Alberta) came into force on July 1, 2004. The legislation provides that a unitholder will not be, as abeneficiary, liable for any act, default, obligation or liability of thetrustee that arises after the legislation came into force.

 

Our operations will be conducted, upon theadvice of counsel, in such a way and in such jurisdictions as to avoid as faras possible any material risk of liability on the Unitholders for claimsagainst us.

 

Nevertheless, notwithstanding the terms ofthe Trust Indenture and the aforementioned legislation, Unitholders may not beprotected from our liabilities to the same extent as shareholders are protectedfrom the liabilities of corporations and we cannot guarantee that any assetswould be available to fully reimburse Unitholders should they become subject topersonal liability and seek to rely upon the indemnification of Unitholdersprovided for in the Trust Indenture.

 

**We use enhanced oil recovery methods thatare subject to significant risk factors which could lead to the delay orcancellation of some or all of our enhanced oil recovery projects, which couldadversely affect the market price of our Trust Units and our distributions toUnitholders.**

** **

Penn West utilizes new drilling andcompletion technologies, including horizontal multi fracture completions,intended to increase the resource recovery from known producing oil and naturalgas fields.  There is potential Penn Westmay not realize the anticipated increase in resource recovery from theemployment of such techniques due to particular reservoir characteristics orother adverse factors.  We currently useconventional artificial lift technology to recover heavy oil from bitumendeposits at our Peace River oil sands project. The potential or planned use of enhanced oil recovery (“**EOR**”) methods such as steam injection(Steam Assisted Gravity Drainage, Cyclical Steam Stimulation and SteamFlooding), solvent injection and firefloods to increase the ultimate recoveryof oil resources in place are subject to significant risk factors.  These factors, which could lead to a delayedor cancelled EOR application in the Peace River oil sands project, include butare not limited to the following:

 

·               changing economic conditions (commodity pricing, operating andcapital expenditure fluctuations);

·               changingengineering and technical conditions (ability to apply EOR methods to thereservoir and the production response thereto);

·               thelarge development program may need to spread over a longer time period thaninitially planned due to requirement to allocate capital expenditures todifferent periods;

·               surfaceaccess and deliverability issues (First Nations relations, weather, pipeline,road and processing matters);

·               environmentalregulations, relating to such items as green house gas emissions and access towater,  which could impact capital andoperating costs; and

·               financing(the availability of sufficient financing on acceptable terms).

 

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The use or potential or planned use of carbondioxide miscible flooding to increase the oil recovery from large legacy oilpools such as Pembina and South Swan Hills is subject to significant riskfactors which could lead to the delay or cancellation of some or all of theseprojects.  These factors include, but arenot limited to:

 

·               carbondioxide infrastructure (the capture and transportation of the miscible agent tous at an economic cost);

·               changingeconomic conditions (commodity pricing, operating and capital expenditurefluctuations);

·               changingengineering and technical conditions (ability to apply carbon dioxide EORmethods to the reservoir and the production response thereto);

·               thelarge development program may need to be spread over a longer time period thanplanned due to capital allocation requirements;

·               the need to obtain required approvals fromregulatory authorities from time to time;

·               surfaceaccess and deliverability issues (weather, pipeline, road and processingmatters); and

·               financing(the availability of sufficient financing on acceptable terms).

 

The engineering, geological, production andassociated dewatering techniques employed on coal bed methane projects arerelatively new in the Western Canadian Sedimentary Basin and their applicationto our coal bed methane prone properties is subject to this risk in addition torisk factors similar to those listed in the preceding paragraphs related to thePeace River oil sands and carbon dioxide miscible flooding.

 

**Unitholders may suffer dilution.**

** **

We may make future acquisitions or enter intofinancings or other transactions involving the issuance of our securities,which may be dilutive to Unitholders.  Inaddition, we may determine to redeem the currently outstanding ConvertibleDebentures for Trust Units or to settle the interest and/or pay the redemptionprice at maturity of such Convertible Debentures by issuing additional TrustUnits.  Unitholders may suffer dilutionin the event of any such issuance of Trust Units.

 

**Seasonal factors and unexpected weatherpatterns may lead to declines in our activities and thereby adversely affectour business, the market price of our Trust Units and distributions to ourUnitholders.**

** **

The level of activity in the Canadian oil andgas industry is influenced by seasonal weather patterns.  Wet weather and spring thaw may make the groundunstable.  Consequently, municipalitiesand provincial transportation departments enforce road bans that restrict themovement of rigs and other heavy equipment, thereby reducing activity levels.  Also, certain oil and gas producing areas arelocated in areas that are inaccessible other than during the winter monthsbecause the ground surrounding the sites in these areas consists of swampyterrain.  Seasonal factors and unexpectedweather patterns may lead to declines in our exploration, development andproduction activities and thereby adversely affect our results of operationsand business.

 

**Changes to Canadian federal income taxlegislation or other factors could result in us losing our mutual fund truststatus, which would have an adverse effect on the market price of the TrustUnits and distributions to our Unitholders.**

** **

In order for us to maintain our status as amutual fund trust under the Tax Act, we must not be established or maintainedprimarily for the benefit of Non-Residents unless we satisfy the requirementsof certain exceptions.  The TrustIndenture provides that we will use our best commercial efforts to maintain ourstatus as a mutual fund trust under the Tax Act.  Generally speaking, the Tax Act provides thata trust will permanently lose its “mutual fund trust” status (which isessential to the income trust structure) if it is established or maintainedprimarily for the benefit of Non-Residents (which is generally interpreted tomean that the majority of unitholders must not be Non-Residents), unless at therelevant time, “all or substantially all” of the trust’s property consists ofproperty other than taxable Canadian property (the “**TCP Exception**”).  Basedon information obtained by us through our transfer agent and financialintermediaries, in February 2009,we estimate that approximately 61%of our issued and outstanding Trust Units were held by Non-Residents.  We have determined that we currently meet therequirement of the TCP Exception, and as a result, the Trust Indenture does notcurrently have a specific limit on the percentage of Trust Units that may beowned by Non-Residents.

 

There is no assurance that the TCP Exceptionwill continue to be available to us or that the Government of Canada will notintroduce new changes or proposals to tax regulations directed at Non-Residentownership which, given our level of

 

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Non-Residents ownership, may result in uslosing our mutual fund trust status or could otherwise detrimentally affect usand the market price of the Trust Units.

 

**If we cease to qualify as a “mutual fundtrust” under the Canadian tax laws, adverse tax consequences would arise forthe Trust and our Unitholders.**

** **

For such period of time as we operate in atrust structure, we intend to continue to qualify as a mutual fund trust forpurposes of Canadian federal income tax laws. We may not, however, always be able to satisfy any future requirementsfor the maintenance of mutual fund trust status.  Should our status as a mutual fund trust belost or successfully challenged by a relevant tax authority, certain adverseconsequences may arise for us and our Unitholders.  Some of the significant consequences oflosing mutual fund trust status are as follows:

 

·               We would be taxed on certain types of income distributed toUnitholders, including income generated by the royalties we hold.  Payment of this tax may have adverseconsequences for some Unitholders, particularly Unitholders that are notresidents of Canada and residents of Canada that are otherwise exempt fromCanadian income tax or hold their Trust Units in a tax deferred account.

 

·               We would cease to be eligible for the capital gains refund mechanismavailable under Canadian tax laws if we ceased to be a mutual fund trust.

 

·               Trust Units held by Unitholders that are not residents of Canadawould become taxable Canadian property. These Non-Resident holders would be subject to Canadian income tax onany gains realized on a disposition of Trust Units held by them.

 

·               Trust Units would cease to be a qualifiedinvestment for trusts governed by registered retirementsavings plans (“**RRSPs**”),registered education savings plans (“**RESPs**”),deferred profit sharing plans (“**DPSPs**”),registered disability savings plan (“**RDSPs**”),registered retirement income funds (“**RRIFs**”)and tax free savings accounts (“**TFSAs**”)(collectively, the “**Exempt****Plans**”).  Where, at the end of a month, aRRSP, DPSP, RESP or RRIF holds Trust Units that cease to be a qualifiedinvestment, the plan must, in respect of that month, pay a tax equal to 1% ofthe fair market value of the Trust Units at the time such Trust Units wereacquired by the plan.  Trusts governed byRRSPs, RDSPs, TSFAs or RRIFs which hold Trust Units that are not qualified investmentswill be subject to tax on the income attributable to the Trust Units while theyare not qualified investments, including the full capital gains, if any,realized on the disposition of such Trust Units.  Where a trust governed by a RRSP or a RRIF acquiresTrust Units that are not qualified investments, the value of the investment isincluded in the income of the annuitant for the year of the acquisition.  Trusts governed by RESPs which hold TrustUnits that are not qualified investments can have their registration revoked bythe CRA.  The holder of a RDSP or TSFA which holds Trust Units that are not qualifiedinvestments will be subject to tax equal to 50% of the fair market value of theTrust Units.

 

In addition, we may take certain measures inthe future to the extent we believe necessary to ensure that we maintain ourstatus as a mutual fund trust.  Thesemeasures could be adverse to certain Unitholders, particularly Non-Residents.

 

**There might not always be an active tradingmarket in the United States and/or Canada for the Trust Units and/or theConvertible Debentures.**

** **

While there is currently an active tradingmarket for the Trust Units in both the United States and Canada, we cannotguarantee that an active trading market will be sustained in eithercountry.  If an active trading market inthe Trust Units is not sustained, the trading liquidity of the Trust Units willbe limited and the market value of the Trust Units may be reduced.

 

There is not currently an active tradingmarket for the Convertible Debentures in Canada, and we cannot guarantee thatan active trading market will develop. If an active trading market in the Convertible Debentures does notdevelop, the trading liquidity of the Convertible Debentures will remainlimited and the market value of the Convertible Debentures may be adverselyaffected.

 

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**The economic impact on us of claims ofaboriginal title is unknown.**

** **

Aboriginal peoples have claimed aboriginaltitle and rights to portions of western Canada. We are not aware that any claims have been made in respect of ourproperties and assets; however, if a claim arose and was successful this couldhave an adverse effect on our results of operations and business.

 

**Our exploration and development activitiesmay be delayed if drilling and related equipment is unavailable or if access todrilling locations is restricted.  Theseevents could have an adverse impact on our business.**

 

Oil and natural gas exploration anddevelopment activities depend on the availability of drilling and relatedequipment (typically leased from third parties) in the particular areas wheresuch activities will be conducted. Demand for such limited equipment or access restrictions may affect theavailability of such equipment to us and may delay exploration and developmentactivities.  To the extent we are not theoperator of our oil and gas properties, we depend on such operators for thetiming of activities related to such properties and are largely unable to director control the activities of the operators.

 

**Our directors and management may haveconflicts of interest that may create incentives for them to act contrary to orin competition with the interests of our Unitholders.**

** **

The directors and officers of PWPL areengaged in, and will continue to engage in, other activities in the oil andnatural gas industry and, as a result of these and other activities, thedirectors and officers of PWPL may become subject to conflicts of interest.  The ABCA provides that in the event that adirector has an interest in a contract or proposed contract or agreement, thedirector must disclose his interest in such contract or agreement and mustrefrain from voting on any matter in respect of such contract or agreementunless otherwise provided under the ABCA. To the extent that conflicts of interest arise, such conflicts will beresolved in accordance with the provisions of the ABCA and our Code of BusinessConduct and Ethics.

 

**Our Trust Units may from time to time tradeat a price that is less than our net asset value per Trust Unit.**

** **

Our net asset value from time to time willvary depending upon a number of factors beyond our control, including oil andgas prices.  The trading price of theTrust Units from time to time is determined by a number of factors, some ofwhich are beyond our control and such trading price may be greater or less thanour net asset value.

 

**The ability ofresidents of the United States to enforce civil remedies against us and ourdirectors, officers and experts may be limited.**

 

Both the Trust and PWPL are organized underthe laws of Alberta, Canada and our respective principal places of business arein Canada.  Most of our directors and allof our officers and the experts named herein are residents of Canada, and asubstantial portion of our assets and all or a substantial portion of theassets of such persons are located outside the United States.  As a result, it may be difficult forinvestors in the United States to effect service of process within the UnitedStates upon those directors, officers and experts who are not residents of theUnited States or to enforce against them judgments of United States courtsbased upon civil liability under the United States federal securities laws orthe securities laws of any state within the United States.  There is doubt as to the enforceability inCanada against us or against any of our directors, officers or experts who arenot residents of the United States, in original actions or in actions forenforcement of judgments of United States courts of liabilities based solelyupon the United States federal securities laws or the securities laws of anystate within the United States.

 

**Canadian and United States practices differin reporting reserves and production and our estimates may not be comparable tothose of companies in the United States.**

** **

We report our production and reservequantities in accordance with Canadian practices and specifically in accordancewith NI 51-101.  These practices aredifferent from the practices used to report production and to estimate reservesin reports and other materials filed with the SEC by companies in the UnitedStates.

 

The SEC generally permits oil and gascompanies, in their filings with the SEC, to disclose only proved reservesafter the deduction of royalties and interests of others which are thosereserves that a company has demonstrated by actual production or conclusiveformation tests to be economically producible under existing economic andoperating conditions.  The

 

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securities regulatory authorities in Canadahave adopted NI 51-101, which imposes oil and gas disclosure standards forCanadian public issuers engaged in oil and gas activities.  NI 51-101 permits oil and gas issuers, intheir filings with Canadian securities regulators, to disclose not only provedreserves but also probable reserves, and to disclose reserves and production ona gross basis before deducting royalties. Probable reserves are of a higher risk and are less likely to beaccurately estimated or recovered than proved reserves.  Because we are permitted to disclose reservesin accordance with Canadian disclosure requirements, we have disclosed hereinreserves designated as “probable reserves”. If required to be prepared in accordance with U.S. disclosurerequirements, the SEC’s guidelines would prohibit reserves in this categoryfrom being included.  Moreover, aspermitted by NI 51-101, we have determined and disclosed the net present valueof future net revenue from our reserves using only forecast prices andcosts.  The SEC does not permit thedisclosure of the net present value of future net revenue from reserves basedon forecast prices and costs and generally requires that prices and costs beheld constant at levels in effect at the date of the reserve report.

 

**Our distributions are declared in Canadiandollars and Non-Resident investors are therefore subject to foreign exchangerisk that could adversely affect the amount of distributions received by them.**

** **

Our distributions are declared in Canadiandollars and converted to foreign denominated currencies at the spot exchangerate at the time of payment.  As aconsequence, investors are subject to foreign exchange risk.  To the extent that the Canadian dollarweakens with respect to their currency, the amount of the distribution will bereduced when converted to their home currency.

 

**If oil and gas prices decline, we may berequired under Canadian GAAP and/or U.S. GAAP to write down the value of our assets.**

** **

Canadian GAAP requires that management applycertain accounting policies and make certain estimates and assumptions thataffect reported amounts in our consolidated financial statements.  Under Canadian GAAP, the amounts at whichpetroleum and natural gas property and equipment are carried as net assets onthe balance sheet are subject to a cost-recovery or “ceiling” test, which isbased in part upon estimated future net funds flows from reserves.  If net capitalized costs exceed the estimatedrecoverable amounts, we will have to charge the amount of the excess to netincome.  A decline in the net value ofoil and natural gas properties could cause capitalized costs to exceed the costceiling, resulting in a non-cash charge against net income.  The value of oil and gas properties is highlydependent upon the prices of oil and natural gas.

 

Under U.S. GAAP, the estimated recoverableamounts are calculated based on estimated future net funds flows from provedreserves discounted at 10% and using commodity prices in effect on the balancesheet date.  The use of discounting andconstant prices results in a greater likelihood of a write-down under U.S. GAAPthan Canadian GAAP.

 

**In certain circumstances we may be requiredunder Canadian GAAP to write down the value of the goodwill recorded on ourbalance sheet and incur a non-cash charge against net income.**

** **

Canadian GAAP requires that goodwill balancesbe assessed at least annually for impairment and that any permanent impairmentbe charged to net income.  A permanentreduction in reserves, decline in commodity prices, and/or reduction in theTrust Unit price may indicate goodwill impairment.  As at December 31, 2008 we had $2.020 billion recorded on our balancesheet as goodwill arising primarily out of the Petrofund Acquisition and theCanetic Acquisition.  An impairment wouldresult in a write-down of the goodwill value and a non-cash charge against netincome.  The calculation of impairmentvalue is subject to management estimates and assumptions.

 

**A decrease in the fair market value of ourhedging instruments could result in a non-cash charge against our income underCanadian GAAP.**

** **

Canadian GAAP in respect of accounting forfinancial instruments may result in non-cash charges against income as a resultof changes in the fair market value of hedging instruments.  A decrease in the fair market value of thehedging instruments as the result of fluctuations in commodity prices and/orforeign exchange rates may result in a non-cash charge against income.

 

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**United States Unitholders may besubject to passive foreign investment company rules.**

 

United States Unitholders (meaning, for the purposesof this section, tax residents for United States federal income tax purposes asdefined under Section 7701 of the United States Internal Revenue Code, asamended (the “**Code**”)) should beaware that the United States Internal Revenue Service may determine that theTrust is a “passive foreign investment company” (a “**PFIC**”) under Section 1297(a) of the Code for the2008 taxable year and in subsequent taxable years. The Trust will be a PFIC ifat least 75% of its income consists of dividends, interest, and other passiveitems or if 50% or more of the average value of its assets (on a gross valuebasis) consist of assets that would produce passive income.  In determining whether it is a PFIC, aforeign corporation is required to take into account a pro rata portion of theincome and assets of each corporation in which it owns, directly or indirectly,at least a 25% interest.  To date, wehave received advice that the Trust should not be considered a PFIC for theyears 2002 through 2007, and we do not expect to be considered a PFIC for 2008or 2009.

 

If the Trust is or becomes a PFIC, adverse UnitedStates federal income tax consequences may apply. Any gain recognized on thesale of Trust Units and any excess distributions (as defined under Section 1291(b) ofthe Code) paid on the Trust Units must be ratably allocated to each day in aUnited States Unitholder’s holding period for the Trust Units. The amount ofany such gain or excess distribution allocated to prior years of such UnitedStates Unitholder’s holding period for the Trust Units generally will besubject to United States federal income tax at the highest tax rate applicableto ordinary income in each such prior year, and the United States Unitholderwill be required to pay interest on the resulting tax liability for each suchprior year, calculated as if such tax liability had been due in each such prioryear.

 

Alternatively, a United States Unitholderthat makes a “qualified electing fund” election generally will be subject toUnited States federal income tax on such United States Unitholder’s *pro rata*share of the Trust’s “net capitalgain” and “ordinary earnings” (calculated under United States federal incometax rules), regardless of whether such amounts are actually distributed by theTrust. United States Unitholders should be aware that there can be no assurancethat the Trust will satisfy record keeping requirements or that it will supplyUnited States Unitholders with required information under the “qualifiedelecting fund” rules in the event that the Trust is a PFIC and a UnitedStates Unitholder wishes to make a “qualified electing fund” election. As asecond alternative, a United States Unitholder may make a “mark-to-marketelection” if the Trust is a PFIC and the Trust Units are marketable stockregularly traded on a securities exchange or other market the United StatesSecretary of the Treasury determines as adequate. A retroactive election ispermitted only in accordance with the United States Treasury Regulations and insome circumstances will require the permission of the United StatesCommissioner of the Internal Revenue Service. Additionally, United Statesholders will not be able to make the “mark-to-market election” with respect tothe Trust’s Operating Entities should they be determined to be PFICs. A UnitedStates Unitholder that makes a “mark-to-market election” generally will includein gross income, for each taxable year in which the Trust is a PFIC, an amountequal to the excess, if any, of (a) the fair market value of the TrustUnits as of the close of such taxable year over (b) such United StatesUnitholder’s tax basis in such Trust Units. United States Unitholders arestrongly urged to consult their own tax advisors regarding the United Statesfederal income tax consequences of the Trust’s possible classification as aPFIC and the consequences of such classification.

 

**We are uncertain what impactthe conversion to International Financial Reporting Standards will have on us.**

** **

The Accounting Standards Board of the Canadian Institute of CharteredAccountants has announced that Canadian publicly accountable enterprisesare required to adopt International Financial Reporting Standards (“**IFRS**”), as issued by the InternationalAccounting Standards Board, effective January 1, 2011.  IFRS will require increased financialstatement disclosure as compared to Canadian GAAP. Although IFRS uses aconceptual framework similar to Canadian GAAP, differences in accountingpolicies will need to be addressed by us. We are currently considering theimpact a conversion to IFRS will have on us, including on our financial statements.

 

**We cannot assure you that the distributionsyou receive over the life of your investment will meet or exceed your initialcapital investment, which is at risk.**

** **

Trust Units will have no value when theunderlying petroleum and natural gas properties can no longer be economicallyproduced and, as a result, cash distributions may not represent a “yield” inthe traditional sense and are not comparable to bonds or other fixed yieldsecurities, where investors are entitled to a full return of the principal amountof debt on maturity in addition to a return on investment through interestpayments.  Distributions can represent a*return of* or a *return on* Unitholders’ capital.

 

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**Your redemption right as a Unitholder islimited.**

** **

Unitholders have a limited right to requireus to repurchase their Trust Units, which is referred to as a redemptionright.  See “Information Relating to PennWest — Trust Indenture — Right of Redemption” herein for details of theredemption right.  It is anticipated thatthe redemption right will not be the primary mechanism for Unitholders toliquidate their investment.  The right toreceive cash in connection with a redemption is subject to limitations.  Any securities which may be distributed inspecie to Unitholders in connection with a redemption may not be listed on anystock exchange and a market may not develop for such securities.  In addition, there may be resale restrictionsimposed by law upon the recipients of the securities pursuant to the redemptionright.

 

**MATERIAL CONTRACTS**

** **

Except for contracts entered into in theordinary course of business, the only contracts that are material to us andthat were entered into within the most recently completed financial year orsubsequent thereto, or before the most recently completed financial year butwhich are still material and are still in effect, are the following:

 

(a)                   the Trust Indenture described under “Information Relating to PennWest — Trust Indenture”;

 

(b)                  the Administration Agreement referred to under “Information Relatingto Penn West — Trust Indenture — Our Management” and “Corporate Governance”;

 

(c)                   the Debenture Indentures described under “Information Relating toPenn West — Convertible Debentures”;

 

(d)                  the credit agreement dated January 10, 2008 among PWPL andcertain lenders and other parties in respect of Penn West’s $4 billionsyndicated credit facility, which agreement is described in Note 6 to Penn West’s audited comparativeconsolidated financial statements for the year ended December 31, 2008,which note is incorporated by reference herein;

 

(e)                   the note purchase agreement dated May 31, 2007 among PWPL andthe holders of PWPL’s US$475 million principal amount of 2007 Senior Notes,which agreement is described in Note 6 to Penn West’s audited comparative consolidated financialstatements for the year ended December 31, 2008, which note isincorporated by reference herein.  Seealso “General Development of theBusiness — History and Development - Year Ended December 31, 2007 —Private Placement of 2007 Senior Notes”;

 

(f)                     the note purchase agreement dated May 29, 2008 among PWPL andthe holders of PWPL’s US$480 million and Cdn$30 million principal amount of2008 Senior Notes, which agreement is described in Note 6 to Penn West’s audited comparativeconsolidated financial statements for the year ended December 31, 2008,which note is incorporated by reference herein. See also “General Development ofthe Business — History and Development - Year Ended December 31, 2008 —Private Placement of 2008 Senior Notes”; and

 

(g)                  the note purchase agreement dated July 31, 2008 among PWPL andthe holders of PWPL’s £57 million principal amount of 2008Pounds Sterling Senior Notes, which agreement isdescribed in Note 6 to PennWest’s audited comparative consolidated financial statements for the year endedDecember 31, 2008, which note is incorporated by reference herein.  See also “General Development of the Business — History and Development - YearEnded December 31, 2008 — Private Placement of 2008 Pounds SterlingSenior Notes”.

 

Copies of each of these documents have beenfiled on SEDAR at www.sedar.com.

 

**LEGAL PROCEEDINGS ANDREGULATORY ACTIONS**

** **

There are no legal proceedings that Penn Westis or was a party to, or that any of Penn West’s property is or was the subjectof, during the most recently completed financial year, that were or arematerial to Penn West, and there are no such material legal proceedings thatPenn West knows to be contemplated.  Forthe purposes of the foregoing, a legal proceeding is not considered to be“material” by us if it involves a claim for damages and the amount involved,exclusive of interest and costs, does not exceed ten percent of our currentassets, provided that if any proceeding presents in large degree the same legaland 

 

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factual issues as other proceedings pendingor known to be contemplated, we have included the amount involved in the otherproceedings in computing the percentage.

 

There were no: (i) penalties orsanctions imposed against Penn West by a court relating to securitieslegislation or by a security regulatory authority during the most recentlycompleted financial year; (ii) any other penalties or sanctions imposed bya court or regulatory body against Penn West that would likely be consideredimportant to a reasonable investor in making an investment decision; or (iii) settlementagreements Penn West entered into before a court relating to securitieslegislation or with a securities regulatory authority during Penn West’s mostrecently completed financial year.

 

**TRANSFER AGENTS ANDREGISTRARS**

** **

The transfer agent and registrar for theTrust Units in Canada is CIBC Mellon Trust Company at its principal offices inCalgary, Alberta and Toronto, Ontario. The transfer agent and registrar for the Trust Units in the UnitedStates is Mellon Investor Services LLC at its principal offices in New York,New York.

 

The transfer agent and registrar for the 7.2%Debentures and the 8% 2005 Debentures is Valiant Trust Company at its principaloffices in Calgary, Alberta and Toronto, Ontario.  The transfer agent and registrar for the 6.5%2005 Debentures is Olympia Trust Company at its principal offices in Calgary,Alberta and Toronto, Ontario.  The transferagent and registrar for the 6.5% 2006 Debentures and the 8% 2004 Debentures isComputershare Trust Company of Canada at its principal offices in Calgary,Alberta and Toronto, Ontario.

 

**INTEREST OF MANAGEMENTAND OTHERS IN MATERIAL TRANSACTIONS**

** **

There were no material interests, direct orindirect, of any director or executive officer of PWPL, any person or companythat beneficially owns, or controls or directs, directly or indirectly, morethan 10% of the outstanding Trust Units, or any known associate or affiliate ofany such person, in any transaction within the three most recently completedfinancial years or during the current financial year that has materiallyaffected or is reasonably expected to materially affect Penn West.

 

**INTERESTS OF EXPERTS**

** **

There is no person or company whoseprofession or business gives authority to a report, valuation, statement oropinion made by such person or company and who is named as having prepared orcertified a report, valuation, statement or opinion described or included in afiling, or referred to in a filing, made under National Instrument 51-102 by usduring, or related to, our most recently completed financial year, other thanGLJ and Sproule, our independent engineering evaluators (GLJ and Sproule eachan “**Engineer**” and collectively,the “**Engineers**”), KPMG LLP (“**KPMG**”), our auditors, and Deloitte &Touche LLP, Canetic’s former auditors.

 

The registered or beneficial interests,direct or indirect, in any securities or other property of Penn West or of oneof its associates or affiliates:  (i) heldby an Engineer and by the “designated professionals” (as defined in NationalInstrument 51-102) of the Engineer, when that Engineer prepared the report,valuation, statement or opinion referred to above; (ii) received by anEngineer and by the “designated professionals” of that Engineer, after the timespecified above; or (iii) to be received by an Engineer and by the“designated professionals” of that Engineer; in each case, represented lessthan 1% of each class of our outstanding securities.

 

KPMG is the auditor of Penn West and isindependent within the meaning of the Rules of Professional Conduct of theInstitute of Chartered Accountants, Alberta.

 

Neither GLJ, Sproule or KPMG, nor anydirector, officer or employee of any of such companies, is or is expected to beelected, appointed or employed as a director, officer or employee of Penn Westor of any of our associate or affiliate entities.  John A. Brussa, the Chairman of PWPL, isa partner of Burnet,Duckworth & Palmer LLP, a law firm whichrenders legal services to us.

 

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**ADDITIONAL INFORMATION**

** **

Additionalinformation relating to Penn West may be found on SEDAR at www.sedar.com and onEDGAR at www.sec.gov.  Additionalinformation, including directors’ and officers’ remuneration and indebtedness,principal holders of Penn West’s securities and securities authorized forissuance under equity compensation plans, is contained in Penn West’sinformation circular for its most recent annual meeting of Unitholders thatinvolves the election of directors. Additional financial information is provided in Penn West’s financialstatements and management’s discussion and analysis for its most recentlycompleted financial year.

 

Any document referred to in this AnnualInformation Form and described as being filed on SEDAR at www.sedar.comand on EDGAR at www.sec.gov (including those documents referred to as beingincorporated by reference in this Annual Information Form) may be obtained freeof charge from us by contacting our Investor Relations Department by telephone(toll free: 1-888-770-2633) or by email (investor_relations@pennwest.com).

 

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**APPENDIX A-1**

 

**REPORT OF MANAGEMENTAND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION**

 

**(Form 51-101F3)**

 

Management of Penn West Petroleum Ltd. (“**PWPL**”) on behalf of Penn West Energy Trust (collectively “**Penn West**”) is responsible for thepreparation and disclosure of information with respect to Penn West’s oil andgas activities in accordance with securities regulatory requirements.  This information includes reserves data whichare estimates of proved reserves and probable reserves and related future netrevenue as at December 31, 2008, estimated using forecast prices andcosts.

 

Independent qualified reserves evaluators (orin some cases qualified reserves auditors) have evaluated (or in some casesaudited) Penn West’s reserves data.  Thereport of the independent qualified reserves evaluators (or in some casesqualified reserves auditors) is presented below.

 

The Reserves Committee of the Board ofDirectors of PWPL has:

 

(a)                   reviewed Penn West’s procedures for providing information to theindependent qualified reserves evaluators (or in some cases qualified reservesauditors);

 

(b)                  met with the independent qualified reserves evaluators (or in somecases qualified reserves auditors) to determine whether any restrictionsaffected the ability of the independent qualified reserves evaluators (or insome cases qualified reserves auditors) to report without reservation; and

 

(c)                   reviewed the reserves data with management and the independentqualified reserves evaluators (or in some cases qualified reserves auditors).

 

The Reserves Committee of the Board ofDirectors of PWPL has reviewed Penn West’s procedures for assembling andreporting other information associated with oil and gas activities and hasreviewed that information with management. The Board of Directors has, on the recommendation of the ReservesCommittee, approved:

 

(a)                   the content and filing with securities regulatory authorities of Form 51-101F1containing reserves data and other oil and gas information;

 

(b)                  the filing of Form 51-101F2 which is the report of theindependent qualified reserves evaluators (or in some cases qualified reservesauditors) on the reserves data; and

 

(c)                   the content and filing of this report.

 

Because the reserves data are based onjudgments regarding future events, actual results will vary and the variationsmay be material.  However, any variationsshould be consistent with the fact that reserves are categorized according tothe probability of their recovery.

 

 
| (signed) William E. Andrew                         |   | (signed) Murray R. Nunns                       |
|----------------------------------------------------|--------|------------------------------------------------|
| Chief Executive Officer                            |   | President and Chief Operating Officer          |
|                                               |   |                                           |
| (signed) Daryl Gilbert                             |   | (signed) Jack Schanck                          |
| Director and Chairman****of the Reserves Committee |   | Director and Member of the Reserves  Committee |
|                                               |   |                                           |
| March 26, 2009                                |   |                                           |

 

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**APPENDIX A-2**

 

**REPORT ON RESERVESDATA**

 

**(Form 51-101 F2)**

 

To the Board of Directors of Penn WestPetroleum Ltd. (“**PWPL**”) on behalfof Penn West Energy Trust (collectively “**PennWest**”):

 

1.              Wehave evaluated (or in some cases audited) Penn West’s reserves data as at December 31,2008.  The reserves data are estimates ofproved reserves and probable reserves and related future net revenue as at December 31,2008, estimated using forecast prices and costs.

 

2.              Thereserves data are the responsibility of PWPL’s management.  Our responsibility is to express an opinionon the reserves data based on our evaluation (or in some cases our audit).

 

3.              Wecarried out our evaluation (or in some case or audit) in accordance withstandards set out in the Canadian Oil and Gas Evaluation Handbook (the “**COGE Handbook**”) prepared jointly by theSociety of Petroleum Evaluation Engineers (Calgary Chapter) and the CanadianInstitute of Mining, Metallurgy & Petroleum (Petroleum Society).

 

4.              Thosestandards require that we plan and perform an evaluation (or in some cases anaudit) to obtain reasonable assurance as to whether the reserves data are freeof material misstatement.  An evaluationor audit also includes assessing whether the reserves data are in accordance withprinciples and definitions presented in the COGE Handbook.

 

5.              Thefollowing table sets forth the estimated future net revenue (before deductionof income taxes) attributed to proved plus probable reserves, estimated usingforecast prices and costs and calculated using a discount rate of 10 percent,included in the reserves data of Penn West evaluated and audited by us for theyear ended December 31, 2008, and identifies the respective portionsthereof that we have evaluated and audited and reported on to PWPL’s Board ofDirectors:

 
| **Independent Qualified  Reserves Evaluator or** | ** ** | **Description and  Preparation Date of  Evaluation / Audit** | ** ** | **Location of** | ** ** | **Net Present Value of Future Net Revenue  (millions before income taxes, 10% discount rate)** | ** ** |
|-----------------------------------------------------------------|------------|---------------------------------------------------------------------------------------|------------|----------------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|
| **Auditor**                                                     | ** ** | **Report**                                                                            | ** ** | **Reserves**         | ** ** | **Audited**                                                                                                                                                | ** ** | **Evaluated** | ** ** | **Reviewed** | ** ** | **Total** | ** ** |
| GLJ  Petroleum Consultants Ltd.                                 |       | February 24, 2009                                                                |       | Canada               |       | —                                                                                                                                                     |       | $ | 7,868 |   | — |   | $ | 7,868 |   |
| Sproule  Associates Limited                                     |       | February 26, 2009                                                                |       | Canada               |       | $                                                                                                                                                          | 1,064      |   | $ | 3,582 |   | — |   | $ | 4,646 |   |
| Sproule  Associates Limited                                     |       | February 26, 2009                                                                |       | USA                  |       | —                                                                                                                                                     |       | $ | 88 |   | — |   | $ | 88 |   |
|                                                                 |            |                                                                                       |            |                      |            |                                                                                                                                                            |            |  |  |  |  |  |  |  |  |  |

 

6.              Inour opinion, the reserves data respectively evaluated or audited by us have, inall material respects, been determined and are in accordance with the COGEHandbook.  We express no opinion on thereserves data that we reviewed but did not audit or evaluate.

 

7.              Wehave no responsibility to update our reports referred to in paragraph 4for events and circumstances occurring after their respective preparationdates.

 

8.              Becausethe reserves data are based on judgements regarding future events, actualresults will vary and the variations may be material.  However, any variations should be consistentwith the fact that reserves are categorized according to the probability oftheir recovery.

 

Executed as to our report referred to above:

 
| (signed) GLJ Petroleum Consultants Ltd. |   | (signed) Sproule Associates Limited |
|-----------------------------------------|--------|-------------------------------------|
| Calgary, Alberta, Canada                |   | Calgary, Alberta, Canada            |
| March 26, 2009                     |   | March 26, 2009                 |

 

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**APPENDIX A-3**

 

**STATEMENT OF RESERVES DATA ANDOTHER OIL AND GAS INFORMATION**

** **

Our statement of reserves data and other oiland gas information is set forth below (the “**Statement**”).  The effective date of the Statement is December 31,2008 and the preparation date of the Statement is March 26, 2009.  The Report of Management and Directors onReserves Data and Other Information on Form 51-101F3 and the Report onReserves Data by GLJ and Sproule on Form 51-101F2 are attached asAppendices A-1 and A-2, respectively, to this Annual Information Form.

 

**Disclosure ofReserves Data**

** **

The reserves data set forth below is basedupon: (i) an evaluation prepared by GLJ with an effective date of December 31,2008 contained in the GLJ Report dated February 24,2009; and (ii) an evaluation and audit prepared by Sproule with aneffective date of December 31, 2008 contained in the Sproule Report dated February 26,2009.  The reserves data summarizes ouroil, natural gas liquids and natural gas reserves and the net present values offuture net revenue from these reserves using forecast prices and costs, notincluding the impact of any hedging activities. The reserves data conforms with the requirements of NI 51-101.  We engaged GLJ to evaluate approximately 60%of our proved and proved plus probable reserves.  We engaged Sproule to evaluate approximately32% and to audit approximately 8% of our proved and proved plus probablereserves.  See also “Notes to ReserveData Tables” below.

 

TheEngineering Reports include Alberta crown royalties in accordance with theAlberta New Royalty Framework (NRF) which passed provincial legislation in December 2008.  The Engineering Reports do not take intoaccount either the transitional royalty rate program announced by theGovernment of Alberta on November 19, 2008 or the new royalty incentiveprogram announced by the Government of Alberta on March 3, 2009.  See “Industry Conditions — ProvincialRoyalties and Incentives — Alberta” for details of these programs.

 

The majority of our proved plus probablereserves are located in Canada in the provinces of Alberta, British Columbia,Saskatchewan and Manitoba, and in the Northwest Territories.  We also have minor proved plus probablereserves interests in the United States in the States of Montana, Wyoming andNorth Dakota.  The reserves informationpresented below does not report reserves that are located in the United Statesseparately.  Our properties located inthe United States have proved plus probable gross reserves of approximately 6MMboe, which represents less than one****percentof our total proved plus probable reserves, and have a before tax net presentvalue discounted at 10 percent of approximately $88 million, which representsless than one percent of the total value of our proved plus probable reserves.

 

**It should not beassumed that the estimates of future net revenues presented in the tables belowrepresent the fair market value of the reserves.  There is no assurance that the forecastprices and costs assumptions will be attained and variances could bematerial.  The recovery and reservesestimates of crude oil, natural gas liquids and natural gas reserves providedherein are estimates only and there is no guarantee that the estimated reserveswill be recovered.  Actual crude oil,natural gas and natural gas liquid reserves may be greater than or less thanthe estimates provided herein.  For moreinformation as to the risks involved, see “Risk Factors”.**

** **

----

 

**Reserves Data(Forecast Prices and Costs)**

** **

SUMMARY OF OIL AND GAS RESERVESas of December 31, 2008FORECAST PRICES AND COSTS

 
| ** **                  | ** ** | **RESERVES**                            | ** ** |
|-----------------------------|------------|-----------------------------------------|------------|
| ** **                  | ** ** | **LIGHT AND MEDIUM OIL** | ** ** | **HEAVY OIL** | ** ** |
| **RESERVES CATEGORY**  | ** ** | **Gross  (MMbbl)**                      | ** ** | **Net  (MMbbl)** | ** ** | **Gross  (MMbbl)** | ** ** | **Net  (MMbbl)** | ** ** |
|                        |       |                                    |       |   |   |   |   |   |   |
| PROVED                      |       |                                    |       |   |   |   |   |   |   |
| Developed  Producing        |       | 221                                     |       | 190 |   | 53 |   | 49 |   |
| Developed  Non-Producing    |       | 5                                       |       | 4 |   | 3 |   | 3 |   |
| Undeveloped                 |       | 37                                      |       | 31 |   | 6 |   | 5 |   |
| TOTAL PROVED                |       | 263                                     |       | 225 |   | 62 |   | 57 |   |
|                        |       |                                    |       |   |   |   |   |   |   |
| PROBABLE                    |       | 89                                      |       | 74 |   | 31 |   | 27 |   |
| TOTAL PROVED  PLUS PROBABLE |       | 352                                     |       | 298 |   | 94 |   | 84 |   |

 
| ** **                  | ** ** | **RESERVES**         | ** ** |
|-----------------------------|------------|----------------------|------------|
| ** **                  | ** ** | **NATURAL GAS** | ** ** | **NATURAL GAS LIQUIDS** | ** ** |
| **RESERVES CATEGORY**  | ** ** | **Gross  (Bcf)**     | ** ** | **Net  (Bcf)** | ** ** | **Gross  (MMbbl)** | ** ** | **Net  (MMbbl)** | ** ** |
|                        |       |                 |       |   |   |   |   |   |   |
| PROVED                      |       |                 |       |   |   |   |   |   |   |
| Developed  Producing        |       | 947                  |       | 811 |   | 25 |   | 18 |   |
| Developed  Non-Producing    |       | 65                   |       | 52 |   | 1 |   | 1 |   |
| Undeveloped                 |       | 62                   |       | 54 |   | 1 |   | 1 |   |
| TOTAL PROVED                |       | 1,074                |       | 916 |   | 27 |   | 19 |   |
|                        |       |                 |       |   |   |   |   |   |   |
| PROBABLE                    |       | 402                  |       | 337 |   | 9 |   | 7 |   |
| TOTAL PROVED  PLUS PROBABLE |       | 1,476                |       | 1,253 |   | 37 |   | 26 |   |

 
| ** **                  | ** ** | **RESERVES**                       | ** ** |
|-----------------------------|------------|------------------------------------|------------|
| ** **                  | ** ** | **TOTAL OIL EQUIVALENT** | ** ** |
| **RESERVES CATEGORY**  | ** ** | **Gross  (MMboe)**                 | ** ** | **Net  (MMboe)** | ** ** |
|                        |       |                               |       |   |   |
| PROVED                      |       |                               |       |   |   |
| Developed  Producing        |       | 457                                |       | 392 |   |
| Developed  Non-Producing    |       | 20                                 |       | 16 |   |
| Undeveloped                 |       | 54                                 |       | 46 |   |
| TOTAL PROVED                |       | 532                                |       | 454 |   |
|                        |       |                               |       |   |   |
| PROBABLE                    |       | 197                                |       | 164 |   |
| TOTAL PROVED  PLUS PROBABLE |       | 729                                |       | 617 |   |

 

2

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NET PRESENT VALUES OF FUTURE NET REVENUEBEFORE INCOME TAXES DISCOUNTED AT (%/year)

FORECAST PRICES AND COSTS

 
| ** **                  | ** ** | **0%**    | ** ** | **5%**    | ** ** | **10%**   | ** ** | **15%**   | ** ** | **20%**   | ** ** | **Unit Value Before Income  Tax Discounted at  10%/year(1)** | ** ** |
|-----------------------------|------------|-----------|------------|-----------|------------|-----------|------------|-----------|------------|-----------|------------|---------------------------------------------------------------------------------------|------------|
| **RESERVES CATEGORY**  | ** ** | **(MM$)** | ** ** | **(MM$)** | ** ** | **(MM$)** | ** ** | **(MM$)** | ** ** | **(MM$)** | ** ** | **($/bbl)**                                                                           | ** ** | **($/Mcf)** | ** ** |
|                        |       |      |       |      |       |      |       |      |       |      |       |                                                                                  |       |   |   |
| PROVED                      |       |      |       |      |       |      |       |      |       |      |       |                                                                                  |       |   |   |
| Developed  Producing        |       | 16,949    |       | 11,497    |       | 8,827     |       | 7,231     |       | 6,161     |       | 22.52                                                                                 |       | 3.75 |   |
| Developed  Non-Producing    |       | 679       |       | 462       |       | 354       |       | 288       |       | 242       |       | 22.12                                                                                 |       | 3.69 |   |
| Undeveloped                 |       | 2,117     |       | 1,107     |       | 643       |       | 390       |       | 238       |       | 14.08                                                                                 |       | 2.35 |   |
| TOTAL PROVED                |       | 19,746    |       | 13,066    |       | 9,824     |       | 7,909     |       | 6,641     |       | 21.65                                                                                 |       | 3.61 |   |
|                        |       |      |       |      |       |      |       |      |       |      |       |                                                                                  |       |   |   |
| PROBABLE                    |       | 9,058     |       | 4,521     |       | 2,777     |       | 1,914     |       | 1,414     |       | 16.96                                                                                 |       | 2.83 |   |
|                        |       |      |       |      |       |      |       |      |       |      |       |                                                                                  |       |   |   |
| TOTAL PROVED  PLUS PROBABLE |       | 28,803    |       | 17,587    |       | 12,602    |       | 9,823     |       | 8,056     |       | 20.44                                                                                 |       | 3.41 |   |

 

----

Note:

 

(1)                                  The unit values are based onnet reserve volumes.

 

NET PRESENTVALUES OF FUTURE NET REVENUEAFTER INCOME TAXES DISCOUNTED AT (%/year)

FORECASTPRICES AND COSTS

 
| **RESERVES CATEGORY**  | ** ** | **0%  (MM$)** | ** ** | **5%  (MM$)** | ** ** | **10%  (MM$)** | ** ** | **15%  (MM$)** | ** ** | **20%  (MM$)** | ** ** |
|-----------------------------|------------|---------------|------------|---------------|------------|----------------|------------|----------------|------------|----------------|------------|
|                        |       |          |       |          |       |           |       |           |       |           |       |
| PROVED                      |       |          |       |          |       |           |       |           |       |           |       |
| Developed  Producing        |       | 14,986        |       | 10,528        |       | 8,264          |       | 6,873          |       | 5,920          |       |
| Developed Non-Producing     |       | 530           |       | 372           |       | 293            |       | 244            |       | 209            |       |
| Undeveloped                 |       | 1,594         |       | 836           |       | 480            |       | 284            |       | 164            |       |
| TOTAL PROVED                |       | 17,111        |       | 11,735        |       | 9,038          |       | 7,401          |       | 6,293          |       |
|                        |       |          |       |          |       |           |       |           |       |           |       |
| PROBABLE                    |       | 6,634         |       | 3,352         |       | 2,085          |       | 1,455          |       | 1,089          |       |
|                        |       |          |       |          |       |           |       |           |       |           |       |
| TOTAL PROVED  PLUS PROBABLE |       | 23,744        |       | 15,087        |       | 11,123         |       | 8,856          |       | 7,383          |       |

 

3

----

 

TOTAL FUTURE NET REVENUE(UNDISCOUNTED)as of December 31, 2008FORECAST PRICES AND COSTS

 
| **RESERVES  CATEGORY**         | ** ** | **REVENUE  (MM$)** | ** ** | **ROYALTIES  (MM$)** | ** ** | **OPERATING  COSTS  (MM$)** | ** ** | **DEVELOPMENT  COSTS  (MM$)** | ** ** | **ABANDONMENT  AND  RECLAMATION  COSTS  (MM$)** | ** ** | **FUTURE  NET  REVENUE  BEFORE  INCOME  TAXES  (MM$)** | ** ** | **INCOME  TAXES  (MM$)** | ** ** | **FUTURE  NET  REVENUE  AFTER  INCOME  TAXES  (MM$)** | ** ** |
|--------------------------------|------------|--------------------|------------|----------------------|------------|-----------------------------|------------|-------------------------------|------------|-------------------------------------------------|------------|--------------------------------------------------------|------------|--------------------------|------------|-------------------------------------------------------|------------|
|                           |       |               |       |                 |       |                        |       |                          |       |                                            |       |                                                   |       |                     |       |                                                  |       |
| Proved Reserves                |       | 42,485             |       | 6,507                |       | 13,977                      |       | 1,120                         |       | 1,135                                           |       | 19,746                                                 |       | 2,635                    |       | 17,111                                                |       |
|                           |       |               |       |                 |       |                        |       |                          |       |                                            |       |                                                   |       |                     |       |                                                  |       |
| Proved Plus Probable  Reserves |       | 60,421             |       | 9,695                |       | 18,873                      |       | 1,760                         |       | 1,291                                           |       | 28,803                                                 |       | 5,059                    |       | 23,744                                                |       |

 

FUTURE NET REVENUEBY PRODUCTION GROUPas of December 31, 2008FORECAST PRICES AND COSTS

 
| ** **                     | ** ** | ** **                               | ** ** | **FUTURE NET  REVENUE  BEFORE  INCOME  TAXES  (discounted at** | ** ** | ** **             | ** ** | ** **  | ** ** |
|--------------------------------|------------|------------------------------------------|------------|--------------------------------------------------------------------------|------------|------------------------|------------|-------------|------------|
| ** **                     | ** ** | ** **                               | ** ** | **10%/year)**                                                            | ** ** | **UNIT VALUE(3)** | ** ** |
| **RESERVES CATEGORY**     | ** ** | **PRODUCTION GROUP**                | ** ** | **(MM$)**                                                                | ** ** | **($/bbl)**            | ** ** | **($/Mcf)** | ** ** |
|                           |       |                                     |       |                                                                     |       |                   |       |        |       |
| Proved  Reserves               |       | Light and  Medium Crude Oil(1)           |       | 4,263                                                                    |       | 22.54                  |       | 3.76        |       |
|                           |       | Heavy Oil(1)                             |       | 1,096                                                                    |       | 17.95                  |       | 2.99        |       |
|                           |       | Natural  Gas(2)                          |       | 4,369                                                                    |       | 22.17                  |       | 3.70        |       |
|                           |       | Non-Conventional  Oil and Gas Activities |       | 97                                                                       |       | 14.86                  |       | 2.48        |       |
|                           |       | TOTAL                                    |       | 9,824                                                                    |       | 21.65                  |       | 3.61        |       |
|                           |       |                                     |       |                                                                     |       |                   |       |        |       |
| Proved Plus  Probable Reserves |       | Light and  Medium Crude Oil(1)           |       | 5,196                                                                    |       | 21.30                  |       | 3.55        |       |
|                           |       | Heavy Oil(1)                             |       | 1,573                                                                    |       | 17.63                  |       | 2.94        |       |
|                           |       | Natural  Gas(2)                          |       | 5,672                                                                    |       | 20.86                  |       | 3.48        |       |
|                           |       | Non-Conventional  Oil and Gas Activities |       | 161                                                                      |       | 13.85                  |       | 2.31        |       |
|                           |       | TOTAL                                    |       | 12,602                                                                   |       | 20.44                  |       | 3.41        |       |

 

----

Notes:

 

(1)                                 Including solution gas and otherby-products.

(2)                                 Including by-products but excludingsolution gas.

(3)                                 Other company revenue and costs notrelated to a specific production group have been allocated proportionately toeach production group.  Unit values arebased on net reserve volumes.

 

**Notes toReserves Data Tables**

** **

1.              Columns may not add due to rounding.

 

2.              The crude oil, natural gas liquids and natural gas reservesestimates presented in the Engineering Reports are based on the definitions andguidelines contained in the Canadian Oil and Gas Evaluation Handbook (the “**COGE Handbook**”).  A summary of those definitions are set forthbelow:

 

4

----

 

**ReservesCategories**

 

Reserves areestimated remaining quantities of oil and natural gas and related substancesanticipated to be recoverable from known accumulations, as of a given date,based on:

 

(a)                                 analysis of drilling, geological, geophysical and engineering data;

 

(b)                                the use of established technology; and

 

(c)                                 specified economic conditions, which are generally accepted as beingreasonable.

 

Reserves areclassified according to the degree of certainty associated with the estimates.

 

(d)                                **Proved reserves**are those reserves that can be estimated with a high degree ofcertainty to be recoverable. It is likely that the actual remaining quantitiesrecovered will exceed the estimated proved reserves.

 

(e)                                 **Probable reserves** are those additional reserves that are less certain to be recoveredthan proved reserves.  It is equallylikely that the actual remaining quantities recovered will be greater or lessthan the sum of the estimated proved plus probable reserves.

 

Other criteriathat must also be met for the classification of reserves are provided in theCOGE Handbook.

 

**Developmentand Production Status**

 

Each of thereserves categories (proved and probable) may be divided into developed andundeveloped categories.

 

(f)                                   **Developed reserves** are those reserves that are expected to be recovered from existingwells and installed facilities or, if facilities have not been installed, thatwould involve a low expenditure (for example, when compared to the cost ofdrilling a well) to put the reserves on production.  The developed category may be subdivided intoproducing and non-producing.

 

(i)                                    **Developed producing reserves** are those reserves that are expected to be recovered fromcompletion intervals open at the time of the estimate.  These reserves may be currently producing or,if shut-in, they must have previously been on production, and the date ofresumption of production must be known with reasonable certainty.

 

(ii)                                 **Developed non-producing reserves** are those reserves that either have not been on production, or havepreviously been on production, but are shut-in, and the date of resumption ofproduction is unknown.

 

(g)                                **Undeveloped reserves** are those reserves expected to be recovered from knownaccumulations where a significant expenditure (for example, when compared tothe cost of drilling a well) is required to render them capable ofproduction.  They must fully meet the requirementsof the reserves category (proved, probable) to which they are assigned.

 

In multi-wellpools, it may be appropriate to allocate total pool reserves between thedeveloped and undeveloped categories or to subdivide the developed reserves forthe pool between developed producing and developed non-producing.  This allocation should be based on theestimator’s assessment as to the reserves that will be recovered from specificwells, facilities and completion intervals in the pool and their respectivedevelopment and production status.

 

***L*****evelsof Certainty for Reported Reserves**

* *

Thequalitative certainty levels referred to in the definitions above areapplicable to individual reserve entities (which refers to the lowest level atwhich reserves calculations are performed) and to reported reserves (whichrefers 

 

5

----

 

to the highestlevel sum of individual entity estimates for which reserves estimates arepresented). Reported reserves should target the following levels of certaintyunder a specific set of economic conditions:

 

(a)                                 at least a 90 percent probability that the quantities actuallyrecovered will equal or exceed the estimated proved reserves; and

 

(b)                                at least a 50 percent probability that the quantities actuallyrecovered will equal or exceed the sum of the estimated proved plus probablereserves.

 

A qualitativemeasure of the certainty levels pertaining to estimates prepared for thevarious reserves categories is desirable to provide a clearer understanding ofthe associated risks and uncertainties. However, the majority of reservesestimates are prepared using deterministic methods that do not provide amathematically derived quantitative measure of probability.  In principle, there should be no differencebetween estimates prepared using probabilistic or deterministic methods.

 

Additionalclarification of certainty levels associated with reserves estimates and theeffect of aggregation is provided in the COGE Handbook.

 

3.                                      **Forecast prices and costs**

 

NI 51-101defines “forecast prices and costs” as future prices and costs that are: (i) generallyacceptable as being a reasonable outlook of the future; and (ii) if, andonly to the extent that, there are fixed or presently determinable futureprices or costs to which we are legally bound by a contractual or otherobligation to supply a physical product, including those for an extensionperiod of a contract that is likely to be extended, those prices or costsrather than the prices and costs referred to in subparagraph (i).

 

The forecastcost and price assumptions include increases in wellhead selling prices andtake into account inflation with respect to future operating and capitalcosts.  Crude oil, natural gas andnatural gas liquids benchmark reference pricing, as at December 31, 2008,inflation and exchange rates utilized in the Engineering Reports were as setforth below.  The price assumptions setforth below were provided by GLJ and Sproule.

 

6

----

 

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONSas of December 31, 2008FORECAST PRICES AND COSTS

 
| ** ** | ** ** | **OIL**                          | ** ** | ** **                                  | ** ** | ** **                         | ** ** | ** **                            | ** ** | ** **                | ** ** |
|------------|------------|----------------------------------|------------|---------------------------------------------|------------|------------------------------------|------------|---------------------------------------|------------|---------------------------|------------|
| ** ** | ** ** | **WTI**                          | ** ** | **Edmonton**                                | ** ** | **Hardisty**                       | ** ** | **Cromer**                            | ** ** | **NATURAL**               | ** ** | **EDMONTON LIQUIDS PRICES** | ** ** | ** ** | ** ** | **EXCHANGE** | ** ** |
| **Year**   | ** ** | **Cushing  Oklahoma  ($US/bbl)** | ** ** | **Par Price  40oAPI  ($Cdn/bbl)** | ** ** | **Heavy  12oAPI  ($Cdn/bbl)** | ** ** | **Medium  29.3oAPI  ($Cdn/bbl)** | ** ** | **GAS  AECO  ($Cdn/Mcf)** | ** ** | **Propane  ($Cdn/bbl)** | ** ** | **Butane  ($Cdn/bbl)** | ** ** | **Pentanes  Plus  ($Cdn/bbl)** | ** ** | **INFLATION  RATES(1)  %/year** | ** ** | **RATE(2)  ($US equals  $1 Cdn)** | ** ** |
| ** ** | ** ** | ** **                       | ** ** | ** **                                  | ** ** | ** **                         | ** ** | ** **                            | ** ** | ** **                | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Forecast   |       |                             |       |                                        |       |                               |       |                                  |       |                      |       |   |   |   |   |   |   |   |   |   |   |
| 2009       |       | 55.62                            |       | 66.98                                       |       | 45.07                              |       | 58.58                                 |       | 7.20                      |       | 41.96 |   | 51.64 |   | 68.46 |   | — |   | 0.81 |   |
|       |       |                             |       |                                        |       |                               |       |                                  |       |                      |       |   |   |   |   |   |   |   |   |   |   |
| 2010       |       | 65.71                            |       | 75.86                                       |       | 52.17                              |       | 67.45                                 |       | 7.75                      |       | 46.45 |   | 57.91 |   | 77.53 |   | 2.0 |   | 0.85 |   |
|       |       |                             |       |                                        |       |                               |       |                                  |       |                      |       |   |   |   |   |   |   |   |   |   |   |
| 2011       |       | 71.76                            |       | 81.75                                       |       | 57.16                              |       | 73.14                                 |       | 8.09                      |       | 50.02 |   | 62.38 |   | 83.55 |   | 2.0 |   | 0.86 |   |
|       |       |                             |       |                                        |       |                               |       |                                  |       |                      |       |   |   |   |   |   |   |   |   |   |   |
| 2012       |       | 82.30                            |       | 88.75                                       |       | 63.38                              |       | 79.83                                 |       | 8.54                      |       | 54.31 |   | 67.72 |   | 90.70 |   | 2.0 |   | 0.91 |   |
|       |       |                             |       |                                        |       |                               |       |                                  |       |                      |       |   |   |   |   |   |   |   |   |   |   |
| 2013       |       | 92.01                            |       | 95.44                                       |       | 68.31                              |       | 85.89                                 |       | 9.08                      |       | 58.37 |   | 72.80 |   | 97.54 |   | 2.0 |   | 0.95 |   |
|       |       |                             |       |                                        |       |                               |       |                                  |       |                      |       |   |   |   |   |   |   |   |   |   |   |
| 2014       |       | 93.85                            |       | 97.37                                       |       | 69.70                              |       | 87.62                                 |       | 9.28                      |       | 59.55 |   | 74.27 |   | 99.52 |   | 2.0 |   | 0.95 |   |
|       |       |                             |       |                                        |       |                               |       |                                  |       |                      |       |   |   |   |   |   |   |   |   |   |   |
| 2015       |       | 95.73                            |       | 99.33                                       |       | 71.12                              |       | 89.39                                 |       | 9.48                      |       | 60.76 |   | 75.77 |   | 101.52 |   | 2.0 |   | 0.95 |   |
|       |       |                             |       |                                        |       |                               |       |                                  |       |                      |       |   |   |   |   |   |   |   |   |   |   |
| 2016       |       | 97.64                            |       | 101.34                                      |       | 72.56                              |       | 91.19                                 |       | 9.69                      |       | 61.98 |   | 77.30 |   | 103.57 |   | 2.0 |   | 0.95 |   |
|       |       |                             |       |                                        |       |                               |       |                                  |       |                      |       |   |   |   |   |   |   |   |   |   |   |
| 2017       |       | 99.59                            |       | 103.39                                      |       | 74.04                              |       | 93.04                                 |       | 9.90                      |       | 63.23 |   | 78.86 |   | 105.67 |   | 2.0 |   | 0.95 |   |
|       |       |                             |       |                                        |       |                               |       |                                  |       |                      |       |   |   |   |   |   |   |   |   |   |   |
| 2018       |       | 101.59                           |       | 105.47                                      |       | 75.54                              |       | 94.92                                 |       | 10.11                     |       | 64.51 |   | 80.45 |   | 107.80 |   | 2.0 |   | 0.95 |   |
|       |       |                             |       |                                        |       |                               |       |                                  |       |                      |       |   |   |   |   |   |   |   |   |   |   |
| Thereafter |       | +2                               | %          | +2                                          | %          | +2                                 | %          | +2                                    | %          | +2                        | %          | +2 | % | +2 | % | +2 | % | 2.0 |   | 0.95 |   |

 

----

Notes:

 

(1)                                 Inflation rates for forecasting prices and costs.

 

(2)                                 Exchange rates used to generate the benchmark reference prices inthis table.

 

Weightedaverage actual prices realized, including hedging activities, for the yearended December 31, 2008 were $8.04/Mcffor natural gas, $81.02/bbl forlight and medium crude oil, $74.55/bblfor heavy oil and $68.41/bbl fornatural gas liquids.

 

4.                                      **Future Development Costs**

 

The followingtable sets forth development costs deducted in the estimation of our future netrevenue attributable to the reserve categories noted below.

 

| ** **                         | ** ** | **Forecast Prices and Costs** | ** ** |
|------------------------------------|------------|----------------------------------------------|------------|
| **Year**                           | ** ** | **Proved Reserves  (MM$)**              | ** ** | **Proved Plus Probable  Reserves (MM$)** | ** ** |
|                               |       |                                         |       |   |   |
| 2009                               |       | 321                                          |       | 463 |   |
| 2010                               |       | 266                                          |       | 397 |   |
| 2011                               |       | 151                                          |       | 234 |   |
| 2012                               |       | 109                                          |       | 182 |   |
| 2013                               |       | 82                                           |       | 132 |   |
| Total:  Undiscounted for all years |       | 1,120                                        |       | 1,760 |   |

 

7

----

 

We currently expect to fund the development costs ofthe reserves through internally generated funds flow.

 

There can be no guarantee that funds will be availableor that we will allocate funding to develop all of the reserves attributed inthe Engineering Reports.  Failure todevelop those reserves would have a negative impact on future production andfunds flow and could result in negative revisions to our reserves.

 

The interest and other costs of any external fundingare not included in the reserves and future net revenue estimates and wouldreduce reserves and future net revenue to some degree depending upon thefunding sources utilized.  We do notcurrently anticipate that interest or other funding costs would makedevelopment of any property uneconomic.

 

5.                                       Estimated future well abandonment costs related to reserve wellshave been taken into account by GLJ and Sproule in determining the aggregatefuture net revenue therefrom.

 

6.                                       The forecast price and cost assumptions assumed the continuance ofcurrent laws and regulations.

 

7.                                       All factual data supplied to GLJ and Sproule was accepted asrepresented.  No field inspection wasconducted.

 

8.                                       The estimates of future net revenue presented in the tables above donot represent fair market value.

 

**Reconciliations of Changes in Reserves**

** **

Thefollowing table sets forth the reconciliation of our gross reserves as at December 31,2008, using forecast price and cost estimates derived from the EngineeringReports.

 

RECONCILIATION OFCOMPANY GROSS RESERVESBY PRODUCT TYPEFORECAST PRICES AND COSTS

 
| ** **              | ** ** | **LIGHT AND MEDIUM OIL(2)** | ** ** | **HEAVY OIL(2)**        | ** ** | **NATURAL GAS(2)**                    | ** ** |
|-------------------------|------------|--------------------------------------------|------------|------------------------------|------------|--------------------------------------------|------------|
| **FACTORS**             | ** ** | **Gross  Proved  (MMbbl)**                 | ** ** | **Gross  Probable  (MMbbl)** | ** ** | **Gross  Proved  Plus  Probable  (MMbbl)** | ** ** | **Gross  Proved  (MMbbl)** | ** ** | **Gross  Probable  (MMbbl)** | ** ** | **Gross  Proved  Plus  Probable  (MMbbl)** | ** ** | **Gross  Proved  (Bcf)** | ** ** | **Gross  Probable  (Bcf)** | ** ** | **Gross  Proved  Plus  Probable  (Bcf)** | ** ** |
|                    |       |                                       |       |                         |       |                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |
| December 31,  2007 |       | 190                                        |       | 57                           |       | 248                                        |       | 45 |   | 16 |   | 62 |   | 703 |   | 198 |   | 901 |   |
|                    |       |                                       |       |                         |       |                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Extensions              |       | 6                                          |       | 3                            |       | 9                                          |       | 1 |   | 2 |   | 4 |   | 22 |   | 9 |   | 31 |   |
| Improved  Recovery(1)   |       | 4                                          |       | 1                            |       | 5                                          |       | 6 |   | 13 |   | 18 |   | 16 |   | 7 |   | 23 |   |
| Technical  Revisions    |       | 2                                          |       | (2                           | )          | (1                                         | )          | 3 |   | (6 | ) | (2 | ) | 13 |   | (1 | ) | 12 |   |
| Discoveries             |       | —                                     |       | —                       |       | —                                     |       | — |   | — |   | — |   | 3 |   | 1 |   | 4 |   |
| Acquisitions            |       | 85                                         |       | 30                           |       | 114                                        |       | 13 |   | 4 |   | 17 |   | 495 |   | 186 |   | 681 |   |
| Dispositions            |       | —                                     |       | —                       |       | (1                                         | )          | — |   | — |   | — |   | (15 | ) | (5 | ) | (19 | ) |
| Economic  Factors       |       | 2                                          |       | 1                            |       | 3                                          |       | 4 |   | 2 |   | 6 |   | 17 |   | 7 |   | 24 |   |
| Production              |       | (26                                        | )          | —                       |       | (26                                        | )          | (10 | ) | — |   | (10 | ) | (179 | ) | — |   | (179 | ) |
|                    |       |                                       |       |                         |       |                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |
| December 31,  2008 |       | 263                                        |       | 89                           |       | 352                                        |       | 62 |   | 31 |   | 94 |   | 1,074 |   | 402 |   | 1,476 |   |

 

----

Note:

 

(1)                                  Improved recovery includes thefollowing infill drilling:

 
| Infill  Drilling |   | 2 |   | — |   | 2 |   | 5 |   | 6 |   | 11 |   | 11 |   | 5 |   | 16 |   |
|------------------|--------|---|--------|--------|--------|---|--------|---|--------|---|--------|----|--------|----|--------|---|--------|----|--------|

 

8

----

 

| ** **              | ** ** | **NATURAL GAS LIQUIDS(2)** | ** ** | **TOTAL OIL EQUIVALENT(2)** | ** ** |
|-------------------------|------------|--------------------------------------|------------|---------------------------------------|------------|
| **FACTORS**             | ** ** | **Gross  Proved  (MMbbl)**           | ** ** | **Gross  Probable  (MMbbl)**          | ** ** | **Gross  Proved  Plus  Probable  (MMbbl)** | ** ** | **Gross  Proved  (MMboe)** | ** ** | **Gross  Probable  (MMboe)** | ** ** | **Gross  Proved  Plus  Probable  (MMboe)** | ** ** |
|                    |       |                                 |       |                                  |       |   |   |   |   |   |   |   |   |
| December 31,  2007 |       | 17                                   |       | 5                                     |       | 22 |   | 370 |   | 112 |   | 482 |   |
|                    |       |                                 |       |                                  |       |   |   |   |   |   |   |   |   |
| Extensions              |       | —                               |       | —                                |       | — |   | 11 |   | 7 |   | 18 |   |
| Improved  Recovery(1)   |       | —                               |       | —                                |       | — |   | 13 |   | 15 |   | 28 |   |
| Technical  Revisions    |       | —                               |       | —                                |       | — |   | 7 |   | (9 | ) | (1 | ) |
| Discoveries             |       | —                               |       | —                                |       | — |   | — |   | — |   | 1 |   |
| Acquisitions            |       | 13                                   |       | 5                                     |       | 18 |   | 193 |   | 69 |   | 262 |   |
| Dispositions            |       | —                               |       | —                                |       | — |   | (3 | ) | (1 | ) | (4 | ) |
| Economic  Factors       |       | —                               |       | —                                |       | — |   | 9 |   | 4 |   | 13 |   |
| Production              |       | (4                                   | )          | —                                |       | (4 | ) | (69 | ) | — |   | (69 | ) |
|                    |       |                                 |       |                                  |       |   |   |   |   |   |   |   |   |
| December 31,  2008 |       | 27                                   |       | 9                                     |       | 37 |   | 532 |   | 197 |   | 729 |   |

 

----

Notes:

 

(1)                                  Improved recovery includes thefollowing infill drilling:

 

| Infill  Drilling |   | — |   | — |   | — |   | 9 |   | 7 |   | 16 |   |
|------------------|--------|--------|--------|--------|--------|--------|--------|---|--------|---|--------|----|--------|

 

(2)                                  Columns may not add due torounding.

 

**Additional Information Relating to Reserves Data**

** **

***UndevelopedReserves***

*** ***

Undevelopedreserves are attributed by GLJ and Sproule in accordance with standards andprocedures contained in the COGE Handbook. Proved undeveloped reserves are those reserves that can be estimatedwith a high degree of certainty and are expected to be recovered from knownaccumulations where a significant expenditure is required to render them capableof production.  Probable undevelopedreserves are those reserves that are less certain to be recovered than provedreserves and are expected to be recovered from known accumulations where asignificant expenditure is required to render them capable of production.

 

Insome cases, it will take longer than two years to develop these reserves.  Penn West plans to develop approximately one-half of the proved undevelopedreserves in the Engineering Reports over the next two years and the significantmajority of the proved undeveloped reserves over the next five years.  There are a number of factors that couldresult in delayed or cancelled development, including the following: (i) changingeconomic conditions (due to pricing, operating and capital expenditure fluctuations);(ii) changing technical conditions (including production anomalies, suchas water breakthrough or accelerated depletion); (iii) multi-zonedevelopments (for instance, a prospective formation completion may be delayeduntil the initial completion is no longer economic); (iv) a largerdevelopment program may need to be spread out over several years to optimizecapital allocation and facility utilization; and (v) surface access issues(including those relating to land owners, weather conditions and regulatoryapprovals).

 

***ProvedUndeveloped Reserves***

*** ***

Thefollowing table discloses, for each product type, the gross volumes of provedundeveloped reserves that were first attributed, net of conversions and revisions, in each of the most recent threefinancial years and, in the aggregate, before that time.

 

9

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| ** **     | ** ** | **Light and Medium Oil  (MMbbl)** | ** ** | **Heavy Oil  (MMbbl)**           | ** ** | **Natural Gas  (Bcf)** | ** ** | **NGLs  (MMbbl)**                     | ** ** |
|----------------|------------|--------------------------------------------------|------------|---------------------------------------|------------|-----------------------------|------------|---------------------------------------|------------|
| **Year**       | ** ** | **First  Attributed**                            | ** ** | **Cumulative  at Year End** | ** ** | **First  Attributed**       | ** ** | **Cumulative  at Year End** | ** ** | **First  Attributed** | ** ** | **Cumulative  at Year End** | ** ** | **First  Attributed** | ** ** | **Cumulative  at Year End** | ** ** |
|           |       |                                             |       |                                  |       |                        |       |                                  |       |   |   |   |   |   |   |   |   |
| Prior  thereto |       | 21                                               |       | 21                                    |       | 5                           |       | 5                                     |       | 44 |   | 44 |   | 1 |   | 1 |   |
| 2006           |       | 13                                               |       | 33                                    |       | —                      |       | 2                                     |       | 8 |   | 43 |   | — |   | 1 |   |
| 2007           |       | 5                                                |       | 34                                    |       | 1                           |       | 1                                     |       | 12 |   | 38 |   | — |   | 1 |   |
| 2008           |       | 9                                                |       | 37                                    |       | 5                           |       | 6                                     |       | 44 |   | 62 |   | — |   | 1 |   |

 

GLJand Sproule have assigned 54 MMboe of proven undeveloped reserves in theEngineering Reports under forecast prices and costs, together with $737 millionof associated undiscounted future capital expenditures.  Proven undeveloped capital spending in thefirst two forecast years of the Engineering Reports accounts for $445 million,or 60 percent, of the total forecast. These figures increase to $674 million, or 91 percent, during the firstfive years of the Engineering Reports. The majority of our proven undeveloped reserves evaluated in theEngineering Reports are attributable to futureoil development from CO2 injection, infill drilling andwater injection oil recovery (“EOR”) projects.

 

Forfurther information, see “Risk Factors”.

 

***ProbableUndeveloped Reserves***

*** ***

Thefollowing table discloses, for each product type, the gross volumes of probableundeveloped reserves that were first attributed, net of conversions and revisions, in each of the most recent threefinancial years and, in the aggregate, before that time.

 
| ** **     | ** ** | **Light and Medium Oil  (MMbbl)** | ** ** | **Heavy Oil  (MMbbl)**           | ** ** | **Natural Gas  (Bcf)** | ** ** | **NGLs  (MMbbl)**                     | ** ** |
|----------------|------------|--------------------------------------------------|------------|---------------------------------------|------------|-----------------------------|------------|---------------------------------------|------------|
| **Year**       | ** ** | **First  Attributed**                            | ** ** | **Cumulative  at Year End** | ** ** | **First  Attributed**       | ** ** | **Cumulative  at Year End** | ** ** | **First  Attributed** | ** ** | **Cumulative  at Year End** | ** ** | **First  Attributed** | ** ** | **Cumulative  at Year End** | ** ** |
|           |       |                                             |       |                                  |       |                        |       |                                  |       |   |   |   |   |   |   |   |   |
| Prior  thereto |       | 12                                               |       | 12                                    |       | 3                           |       | 3                                     |       | 26 |   | 26 |   | 1 |   | 1 |   |
| 2006           |       | 11                                               |       | 22                                    |       | —                      |       | 1                                     |       | 7 |   | 33 |   | 1 |   | 2 |   |
| 2007           |       | 5                                                |       | 24                                    |       | 1                           |       | 1                                     |       | 11 |   | 26 |   | — |   | 2 |   |
| 2008           |       | 11                                               |       | 32                                    |       | 14                          |       | 13                                    |       | 57 |   | 79 |   | 1 |   | 2 |   |

 

GLJand Sproule have assigned 61 MMboe of probable undeveloped reserves in theEngineering Reports under forecast prices and costs, together with $547 millionof associated undiscounted future capital expenditures.  Probable undeveloped capital spending in thefirst two forecast years of the Engineering Reports accounts for $232 million,or 43 percent, of the total forecast. These figures increase to $397 million or 72 percent, during the firstfive years of the Engineering Reports. The probable undeveloped reserves evaluated in the Engineering Reportsare primarily associated with provedundeveloped reserve assignments but have a less likely probability of beingrecovered than such associated proved undeveloped reserve assignments.

 

***SignificantFactors or Uncertainties***

*** ***

Thedevelopment schedule of our undeveloped reserves is based on forecast priceassumptions for the determination of economic projects.  The actual prices that occur may besignificantly lower or higher resulting in some projects being delayed oraccelerated, as the case may be.  See“Risk Factors”.

 

Wedo not anticipate that any significant economic factors or other significantuncertainties will affect any particular components of our reserves data.  However, our reserves can be affectedsignificantly by fluctuations in product pricing, capital expenditures,operating costs, royalty regimes and well performance that are beyond ourcontrol.

 

10

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***AdditionalInformation Concerning Abandonment and Reclamation Costs***

*** ***

Abandonmentand reclamation costs in respect of surface leases, wells, facilities andpipelines (collectively, “**A&R Costs**”)are primarily comprised of well bore abandonment and reclamation costs, andliability issues such as flare pit remediation and facility decommissioning,remediation, and reclamation costs. A&R Costs are estimated using our experience conducting annualabandonment and reclamation programs over the past several years.

 

Wereview suspended or standing well bores for reactivation, recompletion or saleand conduct systematic abandonment programs for those well bores that do notmeet our criteria.  A portion of ourliability issues are retired every year and facilities are decommissioned whenall the wells producing to them have been abandoned.  All of our liability reduction programs takeinto account seasonal access, high priority and stakeholder issues, andopportunities for multi-location programs to reduce costs.

 

Asof December 31, 2008, we expect to incur A&R Costs in respect ofapproximately 22,288 net wellbores and 2,267 facilities.  The total amount of A&R Costs, net ofestimated salvage values, that we expect to incur, including wells that extendbeyond the 50-year limit in the Engineering Reports, are summarized in thefollowing table:

 

| **Period**                                    | ** ** | **Abandonment and Reclamation  Costs Escalated at 2%  Undiscounted (MM$ )** | ** ** | **Abandonment and Reclamation  Costs Escalated at 2%  Discounted at 10% (MM$ )** | ** ** |
|-----------------------------------------------|------------|----------------------------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------------------------------------------------------------------------|------------|
|                                          |       |                                                                                                           |       |                                                                                                                          |       |
| Total  liability as at December 31, 2008 |       | 2,679                                                                                                          |       | 272                                                                                                                           |       |
|                                          |       |                                                                                                           |       |                                                                                                                          |       |
| Anticipated  to be paid in 2009               |       | 45                                                                                                             |       | 41                                                                                                                            |       |
|                                          |       |                                                                                                           |       |                                                                                                                          |       |
| Anticipated  to be paid in 2010               |       | 47                                                                                                             |       | 39                                                                                                                            |       |
|                                          |       |                                                                                                           |       |                                                                                                                          |       |
| Anticipated  to be paid in 2011               |       | 49                                                                                                             |       | 37                                                                                                                            |       |

 

Theabove table includes certain A&R Costs, net of salvage values, not includedin the Engineering Reports and not deducted in estimating future net revenue asdisclosed earlier in this Annual Information Form.  Escalated at two percent and undiscounted,the A&R Costs not deducted were $388million, and escalated at two percent and discounted at 10 percent,these A&R Costs were $141 million.

 

**OTHER OILAND GAS INFORMATION**

** **

**Description of Our Properties, Operations andActivities in Our Major Operating Regions**

** **

***Introduction***

 

PennWest participates in the exploration for, and the development and productionof, oil and natural gas principally in western Canada.  Our portfolio of properties as at December 31,2008 includes both unitized and non-unitized oil and natural gasproduction.  In general, the propertiescontain long-life, low-decline rate reserves and include interests in severalmajor oil and gas fields.  The majorityof our proved plus probable reserves are located in Canada in the provinces ofAlberta, British Columbia, Saskatchewan and Manitoba, and in the NorthwestTerritories.  We also have minor provedplus probable reserves interests in the United States in the States of Montana,Wyoming and North Dakota.

 

***MajorOperating Regions***

** **

Our production and reserves are attributed tomore than 400 producingproperties.  No single property accountsfor more than 10 percent ofour proved plus probable reserves.  Penn West’s operations are managed based on five major operatingregions:  (i) Southern District, (ii) CentralDistrict, (iii) Eastern District, (iv) NW Alberta District, and (v) NorthernDistrict.  The following table shows our reported averagedaily production in 2008 and proved plus probable reserves, as at December 31,2008, by major operating regions.  These major operating regions representedapproximately 100 percent of our averagedaily production in 2008 and approximately 100 percent of our total gross proved plus probable reserves (based on forecast cost andprice assumptions) as assigned by GLJ and Sproule in the Engineering Reports.

 

11

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| ** ** | ** ** | **Average Daily Production  in 2008** | ** ** | **Proved Plus Probable Gross Reserves  as at December 31, 2008** | ** ** | **Undeveloped********Land****as at December  31, 2008********(000 net acres)** | ** ** |
|------------|------------|------------------------------------------------------|------------|----------------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------------------------------------------------|------------|
| ** ** | ** ** | **Crude Oil  and NGLs********(bbl/d)**     | ** ** | **Natural Gas********(MMcf/d)**                                                                     | ** ** | **Total  Oil  Equivalent********(boe/d)**                                                               | ** ** | **Crude Oil  and NGLs********(MMbbl)** | ** ** | **Natural  Gas********(Bcf)** | ** ** | **Total  Oil  Equivalent********(MMboe)** | ** ** | ** ** |
| Southern   |       | 29,597                                               |       | 58                                                                                                       |       | 39,331                                                                                                  |       | 157 |   | 620 |   | 261 |   | 826 |   |
| Eastern    |       | 24,730                                               |       | 46                                                                                                       |       | 32,468                                                                                                  |       | 88 |   | 99 |   | 105 |   | 356 |   |
| Central    |       | 30,721                                               |       | 207                                                                                                      |       | 65,149                                                                                                  |       | 14 |   | 412 |   | 82 |   | 435 |   |
| NW Alberta |       | 18,783                                               |       | 35                                                                                                       |       | 24,529                                                                                                  |       | 84 |   | 114 |   | 103 |   | 571 |   |
| Northern   |       | 3,921                                                |       | 144                                                                                                      |       | 27,985                                                                                                  |       | 140 |   | 231 |   | 178 |   | 1,035 |   |
| Total      |       | 107,752                                              |       | 490                                                                                                      |       | 189,462                                                                                                 |       | 483 |   | 1,476 |   | 729 |   | 3,223 |   |
|       |       | 57% of  daily  production                            |       | 43% of  daily  production                                                                                |       |                                                                                                    |       | 66% of  total  reserves |   | 34% of  total  reserves |   |   |   |   |   |

 

Thefollowing map outlines Penn West’s five major operating regions as at December 31,2008:

 

 

The following is a description of our principal oil and natural gasproperties and our related operations and activities by major operating regionas at December 31, 2008.  Information in respect of gross and net acres and well counts is as at December 31,2008, and information in respect of production is for the year ended December 31,2008 except where indicated otherwise. Due to the fact that we have been active at acquiring additionalinterests in our principal properties, the working interest share and interestin gross and net acres and wells as at December 31, 2008 may not directlycorrespond to the stated production for the year, which only includesproduction since the date the interests were acquired by us.  **Theestimates of reserves and future net revenue for individual properties may notreflect the same confidence level as estimates of reserves and future netrevenue for all properties, due to the application of statistical methods ofaggregating individual properties.**

 

12

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**Southern District**

 

TheSouthern District runs within the southern boundaries of Manitoba, Saskatchewanand Alberta.  This district also containsminor operations and land positions in the states of North Dakota, Wyoming****and Montana.  In 2008, production in this district averaged39,300 boe/d, comprised of 29,600 bbl/d of crude oil and natural gas liquidsand 58 MMcf/d of natural gas.

 

Asat December 31, 2008, Penn West had a land position of approximately 2.1million net acres in the Southern District. In 2008, capital investment by Penn West in this district wasapproximately $340million.  PennWest drilled 72 new wells in the Southern District in 2008.  In 2009, Penn West plans overall capitalexpenditures to total about $190 million for the Southern District.

 

InSouthwest Saskatchewan, the predominant play for Penn West is the Leitchville(Lower Shaunavon horizon) tight oil play. This is an unconventional, “resource” play that has been unlocked bymulti-stage horizontal fracture technology. In 2008, Penn West drilled 25 wells in the Lower Shaunavon horizon.  In 2009, Penn West expects to drill another20 to 25 wells to further develop and expand the play.

 

InSoutheast Saskatchewan, Penn West has been active on a number of fronts.  In 2008, our focus was on land acquisition toincrease Penn West’s position on the tight oil play in the Bakken pool and todevelop a strategy to expand Penn West’s knowledge and position on the emergingTorquay play to the eastern edges of the Williston Basin.  Also in 2008, we worked on optimizationopportunities in Penn West’s legacy asset base and participated in the Weyburnunit operated by EnCana Corporation, which is currently under CO2 flood for enhanced oilrecovery.  Penn West holds a 21% interestin this unit.  We plan total capitalexpenditures of approximately $70 million for Southeast Saskatchewan in 2009.

 

InSouthern Alberta, Penn West drilled 38 wells in 2008, targeting mainly theColony and Mid-Mannville horizons.  In2009, Penn West plans to drill up to 45 additional wells in SouthernAlberta.  We plan total capitalexpenditures of approximately $63 million for Southern Alberta in 2009.

 

**Eastern District**

 

TheEastern District straddles the Saskatchewan and Alberta border and is justnorth of the Southern District.  Thisdistrict contains most of Penn West’s heavy oil properties.  The Eastern District is characterized bymulti-zone crude oil potential.  In 2008,production in this district averaged 32,500 boe/d, comprised of 24,700 bbl/d ofcrude oil and natural gas liquids and 46 MMcf/d of natural gas.

 

Asat December 31, 2008, Penn West had a land position of approximately 1.0million net acres in the Eastern District. In 2008, capital investment by Penn West in the Eastern District wasapproximately $160 million with 56 new wells drilled.  In 2009,Penn West expects overall capital expenditures to total about $65 million for theEastern District.

 

Amajor property for Penn West in the Eastern District is Dodsland.  In 2008, Penn West drilled its firsthorizontal injector well in the Dodsland area. In 2009, Penn West plans to drill one additional injector well and two horizontalproducer wells in this area.  We expecttotal capital expenditures of approximately $10 million for the Dodsland areain 2009.

 

**Central District**

 

TheCentral District runs from the eastern border of the Eastern District andstretches from northeast of Edmonton to just north of Calgary and runs west tothe foothills of Alberta.  This districtis Penn West’s largest district in terms of production.  The district is characterized by legacy lightoil assets and gas pools with multi-zone potential.  In 2008, production in this district averagedabout 65,100 boe/d comprised of 30,700 bbl/d of crude oil and natural gasliquids and 207 MMcf/d of natural gas

 

Asat December 31, 2008, Penn West had a land position of approximately 1.6million net acres in the Central District. In 2008, Penn West drilled 38 new wells in this district and made a capitalinvestment of approximately $208million.  In2009, Penn West expects overall capital expenditures to total about $120 million for theCentral District.

 

13

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The Pembina area is a key property for PennWest in the Central District and multi-stage horizontal fracture technology isbeing used to drill both producing wells and injectors to further enhancerecovery in the Pembina area.  Penn Westhas also initiated a CO2 flood pilot project for enhanced oil recoveryin the Pembina area and operates at Joffre, Alberta what is currently Alberta’sonly commercial CO2 flood enhanced oil recoveryproject.  Penn West plans to continuethis CO2 flood project in 2009.

 

Another important property for Penn West inthe Central District is the Wimborne area, which is a light oil play in centralAlberta.  Penn West anticipatesopportunities in terms of enhanced oil recovery using water floods in thisarea, as well as drilling opportunities in certain parts of the area.  In 2009, Penn West plans to formulate andbegin to implement a long-term development plan for this asset.

 

Another important asset for Penn West in theCentral District is the Willesden Green property, which is a legacy assetlocated west of Red Deer, Alberta.  TheWillesden Green area is characterized by multi-zone light oil and gasopportunities.  In 2008, Penn Westdrilled a new gas well in the area and in 2009, we plan to acquire seismic inorder to identify future drilling locations.

 

The Minnehik Buck Lake unit, a sour gasproperty operated by Penn West, is another important asset for Penn West in theCentral District.  The unit currentlyconsists of 17 producing gas wells and includes a sour gas processing plant.  A major sulphur plant turnaround is scheduledfor the third quarter of 2011.  Penn Westis currently evaluating alternatives to safely and cost-effectively handle thehydrogen sulfide and CO2 components of the gas stream.

 

**NWAlberta District**

 

The NW Alberta District is located north ofEdmonton and is bounded by the British Columbia border to the west.  This district is predominantly a light oildistrict characterized by large oil-in-place “legacy assets”.  Due to the nature of the asset base, Penn West’sfocus in this district has been on enhanced oil recovery.  In 2008, production in this district averagedabout 24,500 boe/d, comprised of 18,800 bbl/d of crude oil and natural gasliquids and 34 MMcf/d of natural gas.

 

As at December 31, 2008, Penn West had aland position of approximately 1.1 million net acres in the NW AlbertaDistrict.  In 2008, Penn West drilled 34 new wells in thisdistrict and made a capital investment of approximately $224 million.  In 2009, Penn West expects overall capital expendituresto total about $48 million for the NW Alberta District.

 

An important asset for Penn West in the NWAlberta District is the Seal area, a heavy oil play on oil sands leases,located in the Peace River area of north central Alberta.  In 2008, production from the Seal areaaveraged about 2,000 boe/d.  In 2009,Penn West has postponed its development program in the Seal area due to lowcommodity prices.  Penn West expects toresume its capital program in the Seal area when commodity prices recover.

 

The Swan Hills properties are anotherimportant asset for Penn West in the NW Alberta District.  The Swan Hills properties are light oil inplace “legacy” assets in the Devonian reef complex of the Beaver Hill Lake formationand provide some of Penn West’s longest-life reserves.  In 2008, Penn West implemented a CO2 flood pilot project forenhanced oil recovery in the South Swan Hills unit, which Penn Westoperates.  In 2009, Penn West plans toevaluate long-term development plans aimed at increasing recovery factorsthrough optimization of current water floods and infill drilling opportunitiesin the Swan Hills area.

 

**NorthernDistrict**

 

The Northern District includes northeasternBritish Columbia, the northwestern corners of Alberta (including the Peace RiverArch) and southwestern Northwest Territories. This district is characterized primarily by natural gas with multi-zoneproduction.  In 2008, this districtaveraged about 28,000 boe/d comprised of 3,900 bbl/d of crudeoil and natural gas liquids and 144MMcf/d of natural gas.

 

As at December 31, 2008, Penn West had aland position of approximately 1.8 million net acres in the NorthernDistrict.  In 2008, Penn West drilled six new wells and madea capital investment of approximately $113 million. In 2009, Penn West expects overall capital expenditures to total about $43 million for theNorthern District.

 

14

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In northeast British Columbia, Penn West istesting and evaluating the economic potential of a shale gas play.  In 2008, Penn West drilled three wells tocollect data on this play.  In 2009, PennWest has slowed its development program in this play due to low commodity prices,but we expect to continue evaluation of the play with one well planned in 2009and expected total capital expenditures of $10 million for the year.

 

An important asset for Penn West, located inthe most northern portion of the Northern District, is the Wildboy area, awinter-only access property in northern British Columbia, which targets naturalgas production.  The Wildboy area isserved by a natural gas plant and sales pipeline that is 100% owned andoperated by Penn West and connects to the TransCanada pipeline system inAlberta.

 

Another important property for Penn West inthe Northern District is our position in the Montney natural gas play locatednear Dawson Creek, British Columbia.  In2009, Penn West plans to drill two horizontal wells and expects total capitalexpenditures of $10 million for the Montney play.

 

***Additional Information***

*** ***

None of ourimportant properties, plants, facilities or installations are subject to any material statutory or other mandatory relinquishments,surrenders, back-ins or changes in ownership.

 

We do not have any materialproperties to which reserves have been attributed which are capable ofproducing but which are not producing.  For a discussion of our properties to which reserves have beenattributed and which are capable of producing but which are not producing, see“Additional Information Relating to Reserves Data — Undeveloped Reserves”above.

 

**Oil And Gas Wells**

** **

The followingtable sets forth the number and status of wells in which we had a workinginterest as at December 31, 2008.

 
| ** **             | ** ** | **Producing** | ** ** | ** ** | ** ** | ** **        | ** ** |
|------------------------|------------|---------------|------------|------------|------------|-------------------|------------|
| ** **             | ** ** | **Oil**       | ** ** | **Gas**    | ** ** | **Non-Producing** | ** ** | **Total** | ** ** |
| ** **             | ** ** | **Gross**     | ** ** | **Net**    | ** ** | **Gross**         | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
|                   |       |          |       |       |       |              |       |   |   |   |   |   |   |   |   |   |   |
| Alberta                |       | 10,114        |       | 5,669      |       | 9,756             |       | 4,047 |   | 7,007 |   | 3,851 |   | 26,877 |   | 13,567 |   |
| British  Columbia      |       | 145           |       | 49         |       | 984               |       | 474 |   | 428 |   | 154 |   | 1,557 |   | 677 |   |
| Saskatchewan           |       | 7,740         |       | 5,094      |       | 1,176             |       | 655 |   | 3,255 |   | 1,688 |   | 12,171 |   | 7,437 |   |
| Manitoba               |       | 715           |       | 339        |       | 1                 |       | — |   | 217 |   | 105 |   | 933 |   | 444 |   |
| Northwest  Territories |       | 3             |       | —     |       | 7                 |       | 1 |   | 37 |   | 7 |   | 47 |   | 8 |   |
| Wyoming                |       | —        |       | —     |       | 301               |       | 124 |   | 68 |   | 23 |   | 369 |   | 147 |   |
| Montana                |       | 5             |       | 2          |       | —            |       | — |   | — |   | — |   | 5 |   | 2 |   |
| North Dakota           |       | 16            |       | 6          |       | 1                 |       | — |   | — |   | — |   | 17 |   | 6 |   |
| Total                  |       | 18,738        |       | 11,159     |       | 12,226            |       | 5,301 |   | 11,012 |   | 5,828 |   | 41,976 |   | 22,288 |   |

** **

**Properties with no Attributed Reserves**

** **

The following table sets out the unprovedproperties in which we have an interest as at December 31, 2008.

 

15

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| ** **             | ** ** | **Unproved Properties  (000s of Acres)** | ** ** |
|------------------------|------------|---------------------------------------------------------|------------|
| ** **             | ** ** | **Gross**                                               | ** ** | **Net** | ** ** |
|                   |       |                                                    |       |   |   |
| Alberta                |       | 2,208                                                   |       | 1,793 |   |
| British  Columbia      |       | 756                                                     |       | 569 |   |
| Saskatchewan           |       | 755                                                     |       | 662 |   |
| Manitoba               |       | 153                                                     |       | 147 |   |
| Northwest  Territories |       | 91                                                      |       | 18 |   |
| Wyoming                |       | 16                                                      |       | 9 |   |
| Montana                |       | 3                                                       |       | 2 |   |
| North Dakota           |       | 28                                                      |       | 23 |   |
| Total                  |       | 4,010                                                   |       | 3,223 |   |

 

We currently have no material workcommitments on these lands.  The primarylease or extension term on approximately 532,323 net acres of unprovedproperty will expire by December 31, 2009. The right to explore, develop and exploit these leases will besurrendered unless we qualify them for continuation based on existingproduction, drilling or technical mapping.

 

**Tax Horizon**

** **

Under currently enacted legislation, as aresult of our tax structure, taxable income is transferred from our OperatingEntities to the Trust and from the Trust to Unitholders.  This is primarily accomplished through thededuction by our Operating Entities of the royalties on underlying oil and gasproperties and the deduction of interest on the Internal Notes.  The terms of the Trust Indenture require theTrust to distribute all of its taxable income, therefore, it is currentlyexpected that no income tax liability will be incurred provided we maintainthis organizational structure.  To theextent that taxable income is retained in our Operating Entities to fundcapital expenditures or repay bank debt, it is possible that income taxes couldbe payable at some time in the future.

 

The legislation implementing the SIFT Taxreceived Royal assent on June 22, 2007 with the result that commencing January 1,2011 taxes could be exigible in the Trust as certain distributions will nolonger be a deduction in the calculation of its taxable income.**** Formore information on the SIFT Tax, see “General Development of the Business —History and Development — Year Ended December 31, 2006 — Changes toTaxation of Income Trusts” and “Risk Factors”.

 

The most important variables that willdetermine the level of cash taxes incurred by us in a given year will be theprice of crude oil and natural gas, our capital spending levels and the amountof tax pools available to us.  Assumingthe implementation of the SIFT Tax on January 1, 2011 and that we do notchange our current organizational structure, we estimate that we would not berequired to pay income taxes until at least the 2014 taxation year.  However, if crude oil andnatural gas prices were to strengthen beyond the levels anticipated by thecurrent forward market, our tax pools would be utilized more quickly and we mayexperience higher than expected cash taxes or payment of such taxes in anearlier time period. However, we emphasize that it is difficult to giveguidance on future taxability as we operate within an industry where variousfactors constantly change our outlook, including factors such as acquisitions,divestments, capital spending levels, distribution levels and commodity pricechanges.

 

**Capital Expenditures**

** **

The following table summarizes capitalexpenditures (net of incentives and netof certain proceeds) related to our activities for the year ended December 31,2008, irrespective of whether such costs were capitalized or charged to expensewhen incurred.

 

16

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| ** **              | ** ** | **2008  MM$** | ** ** |
|-------------------------|------------|---------------|------------|
|                    |       |          |       |
| Property  Acquisitions  |       |          |       |
| Proved  Properties      |       | (50           | )          |
| Unproved  Properties    |       | 128           |       |
| Exploration  Costs(1)   |       | 140           |       |
| Development  Costs(2)   |       | 780           |       |
| Corporate  Costs        |       | 47            |       |
| Capital  Expenditures   |       | 1,045         |       |
| Corporate  Acquisitions |       | 5,525         |       |
| Total  Expenditures     |       | 6,570         |       |

 

----

Notes:

 

(1)                                  Costs of land acquired, geological and geophysical capitalexpenditures and drilling costs for 2008 exploration wells drilled.

 

(2)                                  Includes equipping and facilities capital expenditures.

 

**Exploration and Development Activities**

** **

The following table sets forth the gross andnet exploratory and development wells that we participated in during the yearended December 31, 2008.

 

| ** **  | ** ** | **Exploratory Wells** | ** ** | **Development Wells** | ** ** |
|-------------|------------|----------------------------|------------|----------------------------|------------|
| ** **  | ** ** | **Gross**                  | ** ** | **Net**                    | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Oil         |       | 20                         |       | 12                         |       | 259 |   | 124 |   |
| Natural Gas |       | 39                         |       | 27                         |       | 185 |   | 76 |   |
| Service     |       | 8                          |       | 8                          |       | 32 |   | 30 |   |
| Dry         |       | 4                          |       | 4                          |       | 10 |   | 7 |   |
| Total       |       | 71                         |       | 51                         |       | 486 |   | 237 |   |

 

We currently estimate that our capitalexpenditures in 2009 will be toward the lower end of our $600 million to $825 million 2009capital expenditure budget in order to execute our current 2009 capitalprograms.  The primary components of ourprograms are described under the heading “Other Oil and Gas information — Description of Our Properties,Operations and Activities in Our Major Operating Regions”.

 

**Production Estimates**

** **

The following table sets out the volume ofour production estimated for the year ended December 31, 2009 which isreflected in the estimates of gross proved reserves and gross probable reservesdisclosed in the tables contained under “Disclosure of Reserves Data” above.

 
| ** **                      | ** ** | **Light and Medium  Oil** | ** ** | **Heavy Oil** | ** ** | **Natural Gas** | ** ** | **Natural Gas  Liquids** | ** ** | **Total Oil Equivalent** | ** ** |
|---------------------------------|------------|-------------------------------------|------------|--------------------|------------|----------------------|------------|-------------------------------|------------|------------------------------------|------------|
| ** **                      | ** ** | **(bbl/d)**                         | ** ** | **(bbl/d)**        | ** ** | **(Mcf/d)**          | ** ** | **(bbl/d)**                   | ** ** | **(boe/d)**                        | ** ** |
| ** **                      | ** ** | **Gross**                           | ** ** | **Net**            | ** ** | **Gross**            | ** ** | **Net**                       | ** ** | **Gross**                          | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Proved  Producing               |       | 63,520                              |       | 54,172             |       | 23,354               |       | 21,026                        |       | 418,640                            |       | 345,643 |   | 10,459 |   | 7,329 |   | 167,106 |   | 140,133 |   |
| Proved  Developed Non-Producing |       | 972                                 |       | 672                |       | 1,043                |       | 899                           |       | 19,580                             |       | 14,603 |   | 351 |   | 244 |   | 5,629 |   | 4,249 |   |
| Proved  Undeveloped             |       | 2,379                               |       | 2,105              |       | 591                  |       | 522                           |       | 5,283                              |       | 4,119 |   | 40 |   | 32 |   | 3,891 |   | 3,345 |   |
| Total Proved                    |       | 66,870                              |       | 56,949             |       | 24,988               |       | 22,446                        |       | 443,503                            |       | 364,365 |   | 10,850 |   | 7,605 |   | 176,626 |   | 147,727 |   |
| Total  Probable                 |       | 3,214                               |       | 2,749              |       | 2,067                |       | 1,724                         |       | 29,090                             |       | 22,448 |   | 573 |   | 402 |   | 10,702 |   | 8,616 |   |
| Total Proved  Plus Probable     |       | 70,084                              |       | 59,698             |       | 27,055               |       | 24,169                        |       | 472,594                            |       | 386,813 |   | 11,423 |   | 8,007 |   | 187,328 |   | 156,344 |   |

 

17

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No one field accounts for more than****three****percent of theestimated production disclosed above. For more information, see “Other Oil and Gas Information — Description of Our Properties,Operations and Activities in Our Major Operating Regions”.

 

**Production History**

** **

The following table summarizes certaininformation in respect of our production, product prices received, royaltiespaid, production costs and resulting netback for the periods indicated below:

 
| ** **                                | ** ** | ** **                       | ** ** | ** **          | ** ** | ** **        | ** ** | ** **       | ** ** | ** **                  | ** ** |
|-------------------------------------------|------------|----------------------------------|------------|---------------------|------------|-------------------|------------|------------------|------------|-----------------------------|------------|
| ** **                                | ** ** | **Quarter Ended 2008** | ** ** | **Year Ended** | ** ** |
| ** **                                | ** ** | **Mar. 31**                 | ** ** | **June 30**    | ** ** | **Sept. 30** | ** ** | **Dec. 31** | ** ** | **Dec. 31, 2008** | ** ** |
| Average  Daily Production(1)              |       |                             |       |                |       |              |       |             |       |                        |       |
| Light and  Medium Crude Oil (bbl/d)       |       | 71,560                           |       | 71,496              |       | 68,959            |       | 68,219           |       | 70,050                      |       |
| Heavy Oil  (bbl/d)                        |       | 27,338                           |       | 27,460              |       | 28,136            |       | 26,529           |       | 27,366                      |       |
| Gas (MMcf/d)                              |       | 500                              |       | 487                 |       | 500               |       | 476              |       | 490                         |       |
| NGLs (bbl/d)                              |       | 10,118                           |       | 10,461              |       | 9,803             |       | 10,896           |       | 10,320                      |       |
| Combined  (boe/d)                         |       | 192,291                          |       | 190,515             |       | 190,177           |       | 184,908          |       | 189,462                     |       |
|                                      |       |                             |       |                |       |              |       |             |       |                        |       |
| Average Net  Production Prices Received   |       |                             |       |                |       |              |       |             |       |                        |       |
| Light and  Medium Crude Oil ($/bbl)       |       | 92.07                            |       | 116.33              |       | 114.32            |       | 55.02            |       | 94.66                       |       |
| Heavy Oil  ($/bbl)                        |       | 66.64                            |       | 93.12               |       | 98.07             |       | 38.67            |       | 74.55                       |       |
| Gas ($/Mcf)                               |       | 7.98                             |       | 10.20               |       | 8.49              |       | 7.03             |       | 8.43                        |       |
| NGLs ($/bbl)                              |       | 65.43                            |       | 81.49               |       | 83.22             |       | 45.53            |       | 68.45                       |       |
| Combined  ($/boe)                         |       | 68.35                            |       | 87.60               |       | 83.23             |       | 46.79            |       | 71.65                       |       |
|                                      |       |                             |       |                |       |              |       |             |       |                        |       |
| Royalties  Paid                           |       |                             |       |                |       |              |       |             |       |                        |       |
| Light and  Medium Crude Oil ($/bbl)       |       | 14.34                            |       | 19.20               |       | 19.10             |       | 8.70             |       | 15.37                       |       |
| Heavy Oil  ($/bbl)                        |       | 9.98                             |       | 13.50               |       | 14.80             |       | 5.80             |       | 11.09                       |       |
| Gas ($/Mcf)                               |       | 1.76                             |       | 2.02                |       | 1.89              |       | 1.60             |       | 1.84                        |       |
| NGLs ($/bbl)                              |       | 17.30                            |       | 18.99               |       | 21.11             |       | 12.57            |       | 17.38                       |       |
| Combined  ($/boe)                         |       | 12.25                            |       | 15.35               |       | 15.23             |       | 8.89             |       | 12.95                       |       |
|                                      |       |                             |       |                |       |              |       |             |       |                        |       |
| Production  Costs(2)(3)                   |       |                             |       |                |       |              |       |             |       |                        |       |
| Light and  Medium Crude Oil ($/bbl)       |       | 16.51                            |       | 16.75               |       | 17.79             |       | 18.74            |       | 17.43                       |       |
| Heavy Oil  ($/bbl)                        |       | 12.87                            |       | 12.94               |       | 13.63             |       | 14.04            |       | 13.37                       |       |
| Gas ($/Mcf)                               |       | 1.15                             |       | 1.19                |       | 1.26              |       | 1.34             |       | 1.23                        |       |
| NGLs ($/bbl)                              |       | 12.84                            |       | 13.02               |       | 13.84             |       | 14.53            |       | 13.57                       |       |
| Combined  ($/boe)                         |       | 11.64                            |       | 11.91               |       | 12.49             |       | 13.22            |       | 12.31                       |       |
|                                      |       |                             |       |                |       |              |       |             |       |                        |       |
| Transportation                            |       |                             |       |                |       |              |       |             |       |                        |       |
| Light and  Medium Crude Oil ($/bbl)       |       | —                           |       | —              |       | —            |       | —           |       | —                      |       |
| Heavy Oil  ($/bbl)                        |       | 0.08                             |       | 0.06                |       | 0.06              |       | 0.05             |       | 0.06                        |       |
| Gas ($/Mcf)                               |       | 0.18                             |       | 0.19                |       | 0.18              |       | 0.19             |       | 0.19                        |       |
| NGLs ($/bbl)                              |       | —                           |       | —              |       | —            |       | —           |       | —                      |       |
| Combined  ($/boe)                         |       | 0.48                             |       | 0.49                |       | 0.49              |       | 0.49             |       | 0.49                        |       |
|                                      |       |                             |       |                |       |              |       |             |       |                        |       |
| (Gain)/Loss  on Risk Management Contracts |       |                             |       |                |       |              |       |             |       |                        |       |
| Light and  Medium Crude Oil ($/bbl)       |       | 9.35                             |       | 25.26               |       | 25.48             |       | (5.91            | )          | 13.64                       |       |
| Heavy Oil  ($/bbl)                        |       | —                           |       | —              |       | —            |       | —           |       | —                      |       |
| Gas ($/Mcf)                               |       | (0.03                            | )          | 0.99                |       | 0.93              |       | (0.37            | )          | 0.39                        |       |
| NGLs ($/bbl)                              |       | —                           |       | —              |       | —            |       | —           |       | —                      |       |
| Combined  ($/boe)                         |       | 3.41                             |       | 12.01               |       | 11.69             |       | (3.12            | )          | 6.05                        |       |

 

18

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| ** **                          | ** ** | **Quarter Ended 2008** | ** ** | **Year Ended** | ** ** |
|-------------------------------------|------------|----------------------------------|------------|---------------------|------------|
| ** **                          | ** ** | **Mar. 31**                 | ** ** | **June 30**    | ** ** | **Sept. 30** | ** ** | **Dec. 31** | ** ** | **Dec. 31, 2008** | ** ** |
| Netback  Received(4)                |       |                             |       |                |       |   |   |   |   |   |   |
| Light and  Medium Crude Oil ($/bbl) |       | 51.87                            |       | 55.12               |       | 51.95 |   | 33.49 |   | 48.22 |   |
| Heavy Oil  ($/bbl)                  |       | 43.71                            |       | 66.62               |       | 69.58 |   | 18.78 |   | 50.03 |   |
| Gas ($/Mcf)                         |       | 4.92                             |       | 5.81                |       | 4.23 |   | 4.27 |   | 4.78 |   |
| NGLs ($/bbl)                        |       | 35.29                            |       | 49.48               |       | 48.27 |   | 18.43 |   | 37.50 |   |
| Combined  ($/boe)                   |       | 40.57                            |       | 47.84               |       | 43.33 |   | 27.31 |   | 39.85 |   |
|                                     |            |                                  |            |                     |            |  |  |  |  |  |  |  |  |

 

----

Notes:

 

(1)                                  Before deduction of royalties.

 

(2)                                  Operating expenses are composed of direct costs incurred to operateboth oil and gas wells.  A number ofassumptions are required to allocate these costs between oil, natural gas andnatural gas liquids production.

 

(3)                                  Operating recoveries associated with operated properties are chargedto operating costs and accounted for as a reduction to general andadministrative costs.

 

(4)                                  Netbacks are calculated by subtracting royalties, operating costs,transportation costs and losses/gains on commodity and foreign exchangecontracts from revenues.

 

**MarketingArrangements**

** **

Our marketingapproach incorporates the following primary objectives:

 

·                  Ensure security of market and avoidproduction shut-ins due to marketing constraints by dealing with end-users orregionally strategic counterparties wherever possible.

 

·                  Ensure protection of our receivablesby dealing only with credit worthy counterparties who have been subjected toregular credit reviews.

 

·                  Ensure competitive pricing bymanaging pricing exposures through a portfolio of various terms and geographicbasis.

 

·                  Ensure optimization of netbacksthrough careful management of transportation obligations, facility utilizationlevels, blending opportunities and emulsion handling.

 

***Natural Gas Marketing***

*** ***

In 2008, we received an average price from the saleof natural gas, before adjustments for hedging activities, of $8.43/Mcfcompared to $6.85/Mcf realized in 2007. Approximately 87 percent of our natural gas sales are marketed directlywith the balance of natural gas sales marketed in aggregator pools.  We continue to maintain a significantweighting to the Alberta market as this market offers a premium netbackrelative to most other indices.  Inaddition to maximizing netbacks, the current portfolio approach also enhancesour operational flexibility to pursue higher netback opportunities as theybecome available.

 

We continue toconservatively manage our transportation costs. Transportation on all pipelines is closely balanced to supply, and marketcommitments related to export transportation represented less than two percent of sales.

 

***Oil and Liquids Marketing***

*** ***

In terms of our entireliquids production, approximately 65% is light and medium oil, 25% isconventional heavy oil and 10% is NGLs. In regards specifically to crude oil,our average quality is 29 degrees API on a corporate average level, which iscomprised of an average quality for our light and medium oil of 35 degrees APIand an average quality for our conventional heavy oil of 16 degrees API.

 

19

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To reduce risk, we market the majority of ourproduction at the lease level on varying term contracts and actively manage ourheavy oil supply by finding opportunities to optimize netbacks throughblending, trucking and proprietary handling of emulsion. Blending costs arealso controlled through the use of proprietary condensate supply.

 

The following tablesummarizes the net product price received for our production of conventionallight and medium oil (including NGLs) and our conventional heavy oil, beforeadjustments for hedging activities, for the periods indicated:

 
| ** **             | ** ** | **2008**                            | ** ** | **2007**           | ** ** |
|------------------------|------------|-------------------------------------|------------|--------------------|------------|
| ** **             | ** ** | **Light and Medium  Oil** | ** ** | **Heavy Oil** | ** ** | **Light and Medium  Oil** | ** ** | **Heavy Oil** | ** ** |
| **Quarter ended** | ** ** | **($/bbl)**                         | ** ** | **($/bbl)**        | ** ** | **($/bbl)** | ** ** | **($/bbl)** | ** ** |
|                   |       |                                |       |               |       |   |   |   |   |
| March 31          |       | 92.07                               |       | 66.64              |       | 60.93 |   | 41.03 |   |
| June 30           |       | 116.33                              |       | 93.12              |       | 66.57 |   | 42.45 |   |
| September 30      |       | 114.32                              |       | 98.07              |       | 74.49 |   | 48.75 |   |
| December 31       |       | 55.02                               |       | 38.67              |       | 78.20 |   | 48.69 |   |

*** ***

***ForwardContracts***

*** ***

We are exposed to market risks resulting fromfluctuations in commodity prices, foreign exchange rates and interest rates inthe normal course of operations. In accordance with policies approved by ourBoard of Directors, we may, from time to time, manage these risks through theuse of swaps, collars or other financial instruments.  Commodity price risk may be hedged up to amaximum of 50 percent of forecast sales volumes, net of royalties, for thebalance of any current year and one year following and up to 25 percent offorecast sales volumes, net of royalties, for one additional yearthereafter.  This policy is reviewed bymanagement and our Board of Directors from time to time and amended asnecessary.

 

We are also exposed to losses in the event of defaultby the counterparties to these derivative instruments. We manage this risk bydiversifying our hedging portfolio among a number of financially soundcounterparties. For information in relation to marketing arrangements, see“Other Oil and Gas Information — Marketing Arrangements”.

 

As at December 31, 2008, we were not bound byany agreement (including a transportation agreement), directly or through anaggregator, under which we may be precluded from fully realizing, or may beprotected from the full effect of, future market prices for oil or natural gas,except for agreements disclosed by us as financial instruments in accordancewith Section 3861 of the CICA Handbook, or as contractual obligations orcommitments in accordance with Section 3280 of the CICA Handbook.  For information regarding our outstandingfinancial instruments as at December 31, 2008, see Note 13 (Risk management) to our audited annual consolidatedfinancial statements as at and for the year ended December 31, 2008, which have been filedon SEDAR at www.sedar.com.

 

Our transportation obligations and commitments forfuture physical deliveries of crude oil and natural gas do not exceed ourexpected related future production from our proved reserves, estimated usingforecast prices and costs.

 

20

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**APPENDIX B**

 

**MANDATE OF THE AUDITCOMMITTEE**

** **

**Role and Objective**

** **

The Audit Committee (the “**Committee**”) is a committee of the board of directors of PennWest Petroleum Ltd. (the “**Company**”),administrator of Penn West Energy Trust (the “**Trust**”),to which the board has delegated its responsibility for oversight of theintegrity of the Trust’s consolidated financial statements, the Trust’scompliance with legal and regulatory requirements, the independent auditor’squalifications and independence, and the performance of the Trust’s internalaudit function, if any.  The objectivesof the Committee, with respect to Company and the Trust (hereinaftercollectively referred to as “**Penn West**”),are as follows:

 

·                                          To assist the Board in meeting itsresponsibilities (especially for accountability) in respect of the preparationand disclosure of the consolidated financial statements of the Trust andrelated matters;

 

·                                          To provide better communication betweendirectors and independent auditors;

 

·                                          To assist the Board in meeting itsresponsibilities regarding the oversight of the independent auditor’squalifications and independence;

 

·                                          To assist the Board in meeting itsresponsibilities regarding the oversight of the credibility, integrity andobjectivity of financial reports;

 

·                                          To strengthen the role of the non-managementdirectors by facilitating discussions between directors on the Committee,management and independent auditors;

 

·                                          To assist the Board in meeting itsresponsibilities regarding the oversight of the performance of the Company’sindependent auditors and internal audit function, if any; and

 

·                                          To assist the Board in meeting itsresponsibilities regarding the oversight of the Company’s compliance with legaland regulatory requirements.

 

**Mandate and Responsibilitiesof Committee**

** **

·                                          It is the responsibility of the Committee tosatisfy itself on behalf of the Board that the Company’s internal controlsystems are sufficient to reasonably ensure that:

 

·                                          controllable, materialbusiness risks are identified, monitored and mitigated where it is determinedcost effective to do so;

 

·                                          internal controls overfinancial reporting are sufficient to meet the requirements under NationalInstrument 52-109 and the United States Securities Exchange Act of 1934,as amended, and

 

·                                          legal, ethical andregulatory requirements are complied with.

 

·                                          It is a primary responsibility of the Committeeto review the annual and quarterly financial statements of the Trust prior totheir submission to the board of directors for approval.  The process should include but not be limitedto:

 

·                                          reviewing changes inaccounting principles, or in their application, which may have a materialimpact on the current or future years’ financial statements;

 

·                                          reviewing significantaccruals, reserves or other estimates such as the ceiling test calculation;

 

----

 

·                                          reviewing accountingtreatment of unusual or non-recurring transactions;

 

·                                          reviewing the Trust’s statusas a “mutual fund trust” under the *IncomeTax Act* (Canada);

 

·                                          ascertaining compliance withcovenants under loan agreements and Trust Indenture;

 

·                                          reviewing adequacy of theasset retirement obligations;

 

·                                          reviewing disclosurerequirements for commitments and contingencies;

 

·                                          reviewing adjustments raisedby the independent auditors, whether or not included in the financialstatements;

 

·                                          reviewing unresolveddifferences between management and the independent auditors, if any;

 

·                                          obtaining reasonableexplanations of significant variances with comparative reporting periods; and

 

·                                          determine through inquiry ifthere are any related party transactions and ensure the nature and extent ofsuch transactions are properly disclosed.

 

·                                          The Committee is to review, discuss andrecommend for approval by the Board the annual and quarterly financialstatements and related information included in prospectuses, managementdiscussion and analysis (MD&A), information circular-proxy statements andannual information forms (AIF), prior to recommending board approval.

 

·                                          Discuss the Trust’s quarterly results pressreleases, as well as financial information and earnings guidance provided toanalysts and rating agencies (provided that the Committee is not required toreview and discuss investor presentations that do not contain financialinformation or earnings guidance that has not previously been generallydisclosed to the public).

 

·                                          With respect to the appointment of independentauditors by the Board, the Committee shall:

 

·                                          on an annual basis, theCommittee shall review and discuss with the auditors all relationships theauditors have with the Trust and the Company to determine the auditors’independence.  In addition, the Committeewill ensure the rotation of partners on the audit engagement team in accordancewith applicable law and, in order to ensure continuing auditor independence,consider the rotation of the audit firm itself;

 

·                                          be directly responsible forappointing, compensating, retaining and overseeing the work of the independentauditors engaged for the purpose of issuing an auditors’ report or performingother audit, review or attest services for the Trust, including the resolutionof disagreements between management and the independent auditor regardingfinancial reporting, and the independent auditors shall report directly to theCommittee;

 

·                                          review and evaluate theperformance of the lead partner of the independent auditors;

 

·                                          review the basis ofmanagement’s recommendation for the appointment of independent auditors andrecommend to the board appointment of independent auditors and theircompensation;

 

·                                          review the terms ofengagement and the overall audit plan (including the materiality levels to beapplied) of the independent auditors, including the appropriateness andreasonableness of the auditors’ fees;

 

·                                          when there is to be a changein auditors, review the issues related to the change and the information to beincluded in the required notice to securities regulators of such change; and

 

·                                          review and pre-approve anyaudit and permitted non-audit services to be provided by the independentauditors’ firm and consider the impact on the independence of the auditors.

 

·                                          At least annually, obtaining and reviewing the report by theindependent auditors describing the independent auditors’ internal qualitycontrol procedures, any material issues raised by the most recent interimquality-control review, or peer review, of the independent auditors, or by anyinquiry or investigation by governmental or professional authorities, withinthe preceding five years, respecting one or more independent audits carried outby the independent auditors, and any steps taken to deal with any such issues.

 

2

----

 

·                                          Review with theindependent auditors (and internal auditors, if any) their assessment of theinternal controls of the Company, their written reports containingrecommendations for improvement, and management’s response and follow-up to anyidentified weaknesses.  The Committeeshall also review annually with the independent auditors their plan for theiraudit and, upon completion of the audit, their reports upon the financialstatements of Penn West and its subsidiaries.

 

·                                          At least annually,obtaining and reviewing a report by the independent auditors describing (i) allcritical accounting policies and practices used by the Trust, (ii) allalternative accounting treatments of financial information within generallyaccepted accounting principles related to material items that have beendiscussed with management, including the ramifications of the use of suchalternative treatments and disclosures and the treatment preferred by theaccounting firm, and (iii) other material written communications betweenthe accounting firm and management of Penn West.

 

·                                          Obtain assurance fromthe independent auditors that disclosure to the Committee is not requiredpursuant to the provisions of the United States Securities Exchange Act of1934, as amended, regarding the discovery by the independent auditors ofillegal acts.

 

·                                          Pre-approve thecompletion of any audit and permitted non-audit services by the independentauditors and determine which non-audit services the independent auditor isprohibited from providing.  The Committeemay delegate to one or more members of the Committee authority to pre-approvenon-audit services in satisfaction of this requirement and if such delegationoccurs, the pre-approval of non-audit services by the Committee member to whomauthority has been delegated must be presented to the Committee at its firstscheduled meeting following such pre-approval. The Committee shall be entitled to adopt specific policies andprocedures for the engagement of non audit services if:

 

·                                          the pre-approval policiesand procedures are detailed as to the particular service;

 

·                                          the Committee is informed ofeach non-audit service so approved; and

 

·                                          the procedures do notinclude delegation of the Committee’s responsibilities to management.

 

·                                          The Committee will satisfy the pre-approvalrequirement set forth in the above paragraph if:

 

·                                          the aggregate amount of allnon audit services that were not pre approved is reasonably expected toconstitute no more than 5% of the total amount of fees paid by the Trust andits subsidiary entities to the auditors during the fiscal year in which theservices are provided;

 

·                                          the Trust or the subsidiaryentity, as the case may be, did not recognize the services as non-auditservices at the time of the engagement;

 

·                                          the services are promptlybrought to the attention of the Committee and approved, prior to completion ofthe audit, by the Committee or by one or more of its members to whom authorityto grant such approvals has been delegated by the Committee; and

 

·                                          Review, set and approve hiring policies relating to current andformer staff of current and former independent auditors.

 

·                                          Review all publicdisclosure containing financial information before release (provided that theCommittee is not required to review investor presentations that do not containfinancial information or earnings guidance that has not previously beengenerally disclosed to the public).

 

·                                          Review all pendinglitigation to ensure disclosures are sufficient and appropriate.

 

·                                          Satisfy itself that adequateprocedures are in place for the review of the Trust’s public disclosure offinancial information from the Trust’s financial statements and periodicallyassess the adequacy of those procedures.

 

3

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·                                          Review and discuss major financialrisk exposures and the steps management has taken to monitor and control suchexposures.  Discuss guidelines andpolicies to govern the process by which risk assessment and management isundertaken.

 

·                                          Establish procedures independent of management for:

 

·                                          the receipt, retention andtreatment of complaints received by the Trust regarding accounting, internalaccounting controls, or auditing matters; and

 

·                                          the confidential, anonymoussubmission by employees of the Trust of concerns regarding questionableaccounting or auditing matters.

 

·                                          Review any other matters required by law, regulation or stockexchange requirement, or that the Committee feels are important to its mandateor that the Board chooses to delegate to it.

 

·                                          Establish, review and update periodically a Code of Business Conductand Ethics and the Code of Conduct for Senior Officers and Senior FinancialManagement and ensure that management has established systems to enforce thesecodes.

 

·                                          Review management’s monitoring of the Trust’s compliance with theorganization’s Code of Business Conduct and Ethics and the Code of Conduct forSenior Officers and Senior Financial Management.

 

·                                          Review and discuss with the Chief Executive Officer, the ChiefFinancial Officer and the independent auditors, the matters required to bereviewed with those persons in connection with any certificates required byapplicable laws, regulations or stock exchange requirements to be provided bythe Chief Executive Officer and Chief Financial Officer.

 

·                                          Review and discuss major issues regarding accounting principles andfinancial statement presentations, including any significant changes in theTrust’s selection or application of accounting principles.

 

·                                          Review and discuss major issues as to the adequacy of the Trust’sinternal controls and any special audit steps adopted in light of materialcontrol deficiencies.

 

·                                          Review and discuss analyses prepared by management and/or theindependent auditors setting forth significant financial reporting issues andjudgments made in connection with the preparation of the financial statements,including analyses of the effects of alternative generally accepted accountingprinciples methods on the financial statements.

 

·                                          Review and discuss the effect of regulatory and accountinginitiatives, as well as off-balance sheet structures, on the Trust’s financialstatements.

 

·                                          Review and discuss the type and presentation of information to beincluded in earnings press releases, paying particular attention to any use of“pro forma” or “adjusted” non-GAAP information.

 

**Composition**

** **

·                                          This Committee shall be composed of at leastthree individuals appointed by the Board from amongst its members, all of whichmembers will be independent (within the meaning of (a) National Instrument52-110 Audit Committees and (b) Sections 303A.02 and 303A.07(b) ofthe Corporate Governance Rules of the New York Stock Exchange) unless theBoard determines to rely on an exemption in National Instrument 52-110.

 

·                                          The Secretary to the Board shall act asSecretary of the Committee.

 

·                                          A quorum shall be a majority of the members ofthe Committee.

 

4

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·                                          All of the members must be financially literatewithin the meaning of National Instrument 52-110 and Section 303A.07(a) ofthe Corporate Governance Rules of the New York Stock Exchange unless theBoard has determined to rely on an exemption in National Instrument52-110.  Being “financially literate”means members have the ability to read and understand a set of financialstatements that present a breadth and level of complexity of accounting issuesthat are generally comparable to the breadth and complexity of issues that canreasonably be expected to be raised by the Trust’s financial statements.  In addition, at least one member of theCommittee must have accounting or related financial management expertise, asthe Board interprets such qualification in its business judgment.

 

·                                          In connection with the appointment of themembers of the Committee, the Board will determine whether any proposed nomineefor the Committee serves on the audit committee of more than three publiccompanies.  To the extent that anyproposed nominee of PWPL serves on the audit committee of more than threepublic companies, the Board will make a determination as to whether suchsimultaneous services would impair the ability of such member to effectivelyserve on the Company’s Audit Committee and will disclose such determination inthe Trust’s annual information circular and annual report on Form 40-Ffiled with the Securities and Exchange Commission.

 

**Meetings**

** **

·                                          The Committee shallmeet at least four times per year and/or as deemed appropriate by the CommitteeChair.  As part of its job to foster open communication, the Committee shouldmeet at least annually with management, internal auditors (if any) and theindependent auditors in separate executive sessions to discuss any matters thatthe Committee or each of these groups believe should be discussed privately.  In addition, the Committee or at least itsChair should meet with the independent auditors and management quarterly toreview the Trust’s financials.  TheCommittee should also meet with management and independent auditors on anannual basis to review and discuss annual financial statements and themanagement’s discussion and analysis of financial conditions and results ofoperations.

 

·                                          Agendas, with inputfrom management, shall be circulated to Committee members and relevantmanagement personnel along with background information on a timely basis priorto the Committee meetings.

 

·                                          Minutes of eachmeeting shall be prepared by the Secretary to the Committee.

 

·                                          The Chief ExecutiveOfficer and the Chief Financial Officer or their designates shall be available toattend at all meetings of the Committee upon the invitation of the Committee.

 

·                                          The Vice President,Accounting & Reporting and the Vice President, Treasury & Complianceand such other staff as appropriate to provide information to the Committeeshall attend meetings upon invitation by the Committee.

 

**Reporting / Authority**

** **

·                                          At the first Board meeting following aCommittee meeting, the Committee will provide a verbal report to the Board ofthe material matters discussed and material resolutions passed at the Committeemeeting.  The draft minutes of theCommittee meeting will subsequently be provided to all Board members as soon aspracticable.

 

·                                          Supporting schedules and information reviewedby the Committee shall be available for examination by any Director.

 

·                                          The Committee shall have the authority toinvestigate any financial activity of the Trust and to communicate directlywith the internal (if any) and independent auditors.  All employees are to cooperate as requested bythe Committee.

 

·                                          The Committee may retain, and set and pay thecompensation for, persons having special expertise and/or obtain independentprofessional advice, including the engagement of independent counsel and otheradvisors, to assist in fulfilling its duties and responsibilities at theexpense of Penn West.

 

·                                          The Committee may delegate any of its dutiesand responsibilities hereunder to the Committee Chair or any group of membersof the Committee.

 

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·                                          The Committee, in its capacity as a committeeof the Board, shall determine appropriate funding and cause such funding to beavailable (i) to Penn West’s independent auditors for the purpose ofpreparing and issuing an audit report, (ii) to any advisors employed bythe Committee, and (iii) for ordinary administration expenses of theCommittee that are necessary or appropriate in carrying out its duties.

 

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