**Exhibit 99.1**

 

** **

 

**PENN WEST ENERGYTRUST**

** **

**AnnualInformation Form**

**forthe year ended December 31, 2007**

** **

**March 26,2008**

 

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**TABLE OF CONTENTS**

** **
| ** **                                                  | ** ** | **Page** |
|-------------------------------------------------------------|------------|----------|
| GLOSSARY OF TERMS                                           |       | 1        |
| CONVENTIONS                                                 |       | 4        |
| ABBREVIATIONS                                               |       | 4        |
| CONVERSIONS                                                 |       | 5        |
| SPECIAL NOTE REGARDING FORWARD-LOOKING  STATEMENTS          |       | 6        |
| NON-GAAP MEASURES                                           |       | 7        |
| EFFECTIVE DATE OF INFORMATION                               |       | 7        |
| PENN WEST ENERGY TRUST                                      |       | 8        |
| GENERAL DEVELOPMENT OF THE BUSINESS                         |       | 10       |
| DESCRIPTION OF OUR BUSINESS                                 |       | 12       |
| CAPITALIZATION OF PWPL                                      |       | 15       |
| INFORMATION RELATING TO PENN WEST                           |       | 17       |
| CORPORATE GOVERNANCE                                        |       | 25       |
| AUDIT COMMITTEE DISCLOSURES                                 |       | 33       |
| DISTRIBUTIONS TO UNITHOLDERS                                |       | 35       |
| MARKET FOR SECURITIES                                       |       | 36       |
| INDUSTRY CONDITIONS                                         |       | 37       |
| RISK FACTORS                                                |       | 44       |
| MATERIAL CONTRACTS                                          |       | 57       |
| LEGAL PROCEEDINGS AND REGULATORY ACTIONS                    |       | 58       |
| TRANSFER AGENTS AND REGISTRARS                              |       | 58       |
| INTEREST OF MANAGEMENT AND OTHERS IN  MATERIAL TRANSACTIONS |       | 58       |
| INTERESTS OF EXPERTS                                        |       | 58       |
| ADDITIONAL INFORMATION                                      |       | 59       |

 
| **APPENDIX “A” – PENN WEST ENERGY TRUST RESERVES DISCLOSURE**  |
|-------------------------------------------------------------------------------|
|                                                                          | Appendix A-1  – Report of Management and Directors on Reserves Data and Other Information |
|                                                                          | Appendix A-2  – GLJ Report on Reserves Data |
|                                                                          | Appendix A-3  – Statement of Reserves Data – Penn West Energy Trust |
|                                                                          |   |
| **APPENDIX “B” – CANETIC RESOURCES TRUST RESERVES DISCLOSURE** |
|                                                                          | Appendix B-1  – Report of Management and Directors on Reserves Data and Other Information |
|                                                                          | Appendix B-2  – Sproule Report on Reserves Data |
|                                                                          | Appendix B-3  – Statement of Reserves Data – Canetic Resources Trust |
|                                                                          |   |
| **APPENDIX “C” – 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, 2006pursuant to the 7.2% Debenture Indenture, which debentures were assumed by PennWest pursuant to the Vault Acquisition and subsequently began trading on theTSX as securities of Penn West on January 15, 2008 under the symbolPWT.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.

 

“**9.4% Debenture Indenture**” means the trustindenture governing the 9.4% Debentures.

 

“**9.4% Debentures**” means the 9.4%convertible, unsecured, subordinated debentures issued on July 3, 2003pursuant to the 9.4% Debenture Indenture, which debentures were assumed by PennWest pursuant to the Canetic Acquisition and subsequently began trading on theTSX as securities of Penn West on January 16, 2008 under the symbolPWT.DB.A.

 

“**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.

 

“**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.

 

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“**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, the 8% 2005 Debentures and the 9.4%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, the 8% 2005 DebentureIndenture and the 9.4% Debenture Indenture.

 

“**Debenture Trustee**” means, in respect of the6.5% 2005 Debentures, Olympia Trust Company, in respect of each of the 6.5%2006 Debentures, the 8% 2004 Debentures and the 9.4% Debentures, ComputershareTrust Company of Canada, and in respect of each of the 7.2% Debentures and the8% 2005 Debentures, Canadian Western Trust Company.

 

“**GAAP**” means Canadian generally acceptedaccounting principles.

 

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

 

“**GLJ Report**” means the report prepared byGLJ dated February 20, 2008 evaluating the crude oil, natural gas andnatural gas liquids reserves and the net present value of future net revenueattributable to certain of Penn West’s oil and natural gas assets effective asat December 31, 2007.

 

“**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 as at January 11, 2008 following the completion ofthe Vault Acquisition and the Canetic Acquisition.

 

“**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.

 

“**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 Operating Entitiesand to which Penn West is a party as of or prior to January 11, 2008following completion of the Vault Acquisition and the Canetic Acquisition.

 

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

 

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

 

“**Operating Entities**” means, from and after February 1,2008 following the completion of the Vault Acquisition, the Canetic Acquisitionand subsequent internal reorganizations, collectively, PWPL, Penn WestPartnership, Canetic ABC Limited Partnership, Titan Canada Resources, CaneticResources Partnership, Petrofund Ventures Trust, Tika Energy Inc. and UptonResources Inc., each a direct or indirect wholly-owned subsidiary of Penn West,and “**Operating Subsidiary**” meansany 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, theseterms also include all of Penn West’s Subsidiaries on a consolidated basis,which in the case of information presented as at or after January 10, 2008includes Vault and Vault’s former Subsidiaries (if the context requires), andin the case of information presented as at or after January 11, 2008 includesCanetic and Canetic’s former Subsidiaries (where the context requires).

 

“**Penn West Partnership**”****means Penn West Petroleum, a generalpartnership, the partners of which are PWPL, Trocana Resources Inc., CaneticSaskatchewan Trust, 990009 Alberta Inc. and 1167639 Alberta Ltd. effective fromand after January 11, 2008 following the completion of the VaultAcquisition and the Canetic Acquisition.

 

“**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.

 

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

 

“**Sproule Canetic Report**” means the reportprepared by Sproule dated March 3, 2008 evaluating the crude oil, naturalgas and natural gas liquids reserves and the net present value of future netrevenue attributable to certain of Canetic’s oil and natural gas assetseffective as at December 31, 2007.

 

“**Sproule Vault Report**” means the reportprepared by Sproule dated March 3, 2008 evaluating the crude oil, naturalgas and natural gas liquids reserves and the net present value of future netrevenue attributable to certain of Vault’s oil and natural gas assets effectiveas at December 31, 2007.

 

“**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.

 

“**Titan**” means Titan Exploration Ltd., acorporation amalgamated under the ABCA.

 

“**Trust Indenture**” meansthe amended and restated trust indenture between the Trustee and PWPL, amendedand restated as of June 30, 2006.

 

“**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.

 

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

 

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“**United States**” or “**US**” means the United States of America.

 

“**Unitholders**” means holders of our TrustUnits.

 

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

 

“**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 usedherein but not defined herein are defined in NI 51-101 and, unless thecontext otherwise requires, shall have the same meanings herein as inNI 51-101.

 

Unlessotherwise indicated, references herein to “$” or “dollars” are to Canadiandollars. References herein to “US$” are to United States dollars.

 

All financialinformation herein has been presented in Canadian dollars in accordance withCanadian 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 |

 
| **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.                                                                                                                                                                                                                                                                                                                                                                   |

 

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**Whereany disclosure of reserves data is made in this Annual Information Form (includingthe Appendices hereto) that does not reflect all reserves of Penn West orCanetic, as the case may be, the reader should note that the estimates ofreserves and future net revenue for individual properties may not reflect thesame confidence level as estimates of reserves and future net revenue for allproperties, due to the effects of aggregation.**

 

**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.**

 

**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-LOOKING STATEMENTS**

** **

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 by referencein 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 statements are typically identified by words suchas “anticipate”, “continue”, “estimate”, “expect”, “forecast”, “may”, “will”, “project”,“could”, “plan”, “intend”, “should”, “believe”, “outlook”, “potential”, “target”and similar words suggesting future events or future performance. In addition,statements relating to “reserves” or “resources” are deemed to beforward-looking statements as they involve the implied assessment, based oncertain estimates and assumptions, that the reserves and resources describedexist in the quantities predicted or estimated and can be profitably producedin the future. In particular, this document and the documents incorporated byreference herein contain, without limitation, forward-looking statementspertaining to the following: the performance characteristics of our oil andnatural gas properties; the impact on our business, distributionpolicies and Unitholders of the SIFT Tax (as defined herein) and the differentactions that we might take in response to the SIFT Tax; the impact on ourreserves and business of the proposed new Alberta royalty framework;environmental regulation compliance costs and strategy; oil and natural gasproduction level estimates; netback estimates; our business strategy, includingour strategy in respect of our Peace River Oil Sands project, and our coal bedmethane, shale gas and enhanced oil recovery projects; our product balance; thesufficiency of our environmental program; funding sources for distributions anddistribution levels; the funding of our asset retirement obligations; ouroutlook for oil and natural gas prices; our forecast 2008 net capitalexpenditures and the allocation and funding thereof; our exploration anddevelopment plans for our oil and natural gas properties in 2008 and beyond;currency exchange rates; our forecast funds flow; the nature and effectivenessof our risk management strategies; our belief that we will be successful inrenewing or replacing our credit facilities on acceptable terms when theyexpire; the quantity and recoverability of our oil and natural gas reserves andresources; and our ability to economically develop our contingent resources atour Peace River Oil Sands project and convert these resources into reserves.

 

With respectto forward-looking statements contained or incorporated by reference****in this document, we have made assumptionsregarding, among other things: future capital expenditure levels; future oiland natural gas prices and differentials between light, medium and heavy oilprices; future oil and natural gas production levels; future exchange rates;the amount of future cash distributions that we intend to pay; the cost ofexpanding our property holdings; our ability to obtain equipment in a timelymanner to carry out development activities; our ability to market our oil andnatural gas successfully 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.

 

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 arecautioned not to place undue reliance on forward-looking statements included orincorporated by reference in this document, as there can be no assurance thatthe plans, intentions or expectations upon which the forward-looking statementsare based will occur. By their nature, forward-looking statements involvenumerous assumptions, known and unknown risks and uncertainties that contributeto the possibility that the predictions, forecasts, projections and otherforward-looking statements will not occur, which may cause Penn West’s actualperformance and financial results in future periods to differ materially fromany estimates or projections of future performance or results expressed orimplied by such forward-looking statements. These risks and uncertaintiesinclude, among other things: volatility in market prices for oil and naturalgas; 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,undeveloped lands and skilled personnel; incorrect assessments of the value ofacquisitions; geological, technical, drilling and processing problems; generaleconomic conditions in Canada, the US and globally; industry conditions,including fluctuations in the price of oil and natural gas; royalties payablein respect of our oil and natural gas production; changes in governmentregulation of the oil and natural gas industry, including environmentalregulation; fluctuations in foreign exchange or interest rates; unanticipatedoperating events that can reduce production or cause production to be shut-inor delayed; failure to obtain industry partner and other third-party consentsand approvals when required; stock market volatility and market valuations;OPEC’s ability to control production and balance global supply and demand ofcrude oil at desired price levels; political uncertainty, including the risksof hostilities, in the petroleum producing regions of the world; the need toobtain required approvals from regulatory authorities from time to time;failure to realize the anticipated benefits of acquisitions, including theacquisition of Canetic and Vault; changes in federal and provincial taxationlaws and regulations; 

 

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changes in theAlberta royalty framework and their impact on us; uncertainty of obtainingrequired approvals in respect of acquisitions and mergers; and the otherfactors described under “Risk Factors” in this document and in Penn West’spublic filings available in Canada at www.sedar.com and in the United States atwww.sec.gov. Readers are cautioned that this list of risk factors should not beconstrued 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 refers to funds flow and funds flow from operationsderived from cash flow from operating activities. Funds flow is cash flow fromoperating activities before changes in non-cash working capital, expenditureson site reclamation and restoration and payments for surrendered stock options.Funds flow as presented does not have any standardized meaning prescribed byGAAP and therefore it may not be comparable with the calculation of similarmeasures for other entities. Funds flow as presented is not intended torepresent operating cash flow or operating profits for the period nor should itbe viewed as an alternative to cash flow from operating activities, netearnings or other measures of financial performance calculated in accordancewith GAAP.

 

For moreinformation, see Penn West’s Management’s Discussion and Analysis for the yearended December 31, 2007, which includes a reconciliation of “funds flow”to cash flow from operating activities, which has been filed on SEDAR atwww.sedar.com and on EDGAR at www.sec.gov.

 

**EFFECTIVE DATE OF INFORMATION**

** **

**Except where otherwise indicated, theinformation in this Annual Information Form is presented as at the end ofPenn West’s most recently completed financial year, being December 31,2007, which is prior to Penn West’s acquisition of Vault and Canetic.**

 

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**PENN WEST ENERGY TRUST**

** **

**General**

** **

We are anopen-end investment trust created on April 22, 2005 under the laws of theProvince of Alberta pursuant to the Trust Indenture as amended and restated on June 30,2006. At that time, CIBC Mellon Trust Company was appointed as trustee underthe Trust Indenture for a three year period. The beneficiaries of Penn West areholders of the Trust Units. Our principal and head office is located at 2200,425 – 1st Street S.W., Calgary, Alberta, T2P 3L8.

 

We commencedoperations in our current structure on June 1, 2005 after the completionof a plan of arrangement under the ABCA. Pursuant to this plan of arrangement,holders of common shares of PWPL received three (3) Trust Units for eachone (1) of their common shares.

 

**Inter-Corporate Relationships**

** **

The followingare the names, the percentage of votes attaching to all voting securitiesbeneficially owned, or controlled or directed, directly or indirectly, by PennWest, and the jurisdiction of incorporation, continuance, formation or organizationof our direct and indirect material Subsidiaries as at February 1, 2008following the completion of the Vault Acquisition, the Canetic Acquisition andsubsequent internal reorganizations.

 
| ** **                              | ** ** | **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 followingdiagram sets forth the simplified organizational structure of Penn West as at February 1,2008 following the completion of the Vault Acquisition, the Canetic Acquisitionand subsequent internal reorganizations.

 

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Notes:

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

(2)           Cash distributions are made on a monthlybasis to Unitholders based upon, among other things, our funds flow. Ourprimary sources of funds flow are payments from PWPL and our other OperatingEntities pursuant to the NPIs and interest on the principal amount of theInternal Notes.

(3)           PWPL as it presently exists was formedeffective as of January 11, 2008 as part of the completion of the CaneticAcquisition pursuant to the amalgamation of Penn West Petroleum Ltd., Titan,Penn West Canetic Acquisition Ltd., Canetic Resources Inc., Trend Energy Inc.,1336953 Alberta Ltd., 1141702 Alberta Ltd. and Vault Energy Inc.

(4)           PWPL, Trocana Resources Inc., CaneticSaskatchewan Trust, 990009 Alberta Inc. and 1167639 Alberta Ltd. are thepartners of Penn West Partnership effective as of January 11, 2008following the completion of the Vault Acquisition and the Canetic Acquisition.

(5)           The other Operating Entities are direct orindirect wholly-owned subsidiaries of Penn West. Other than PWPL and the PennWest Partnership, 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, 2005***

*** ***

*PWPL TrustConversion*

* *

On May 31,2005, PWPL completed a plan of arrangement whereby holders of common shares ofPWPL received three (3) Trust Units for each one (1) oftheir common shares.

 

*Acquisitionsand Dispositions*

* *

We completed property dispositions, net ofacquisitions, of $5.8 million in 2005. We did not complete any corporateacquisitions in 2005.

 

***YearEnded December 31, 2006***

*** ***

*NYSE Listing*

* *

On June 22,2006, the Trust Units were listed on the NYSE.

 

*PetrofundAcquisition*

* *

Effective June 30,2006, Penn West completed the Petrofund Acquisition, pursuant to which PennWest acquired Petrofund on the basis of an exchange of 0.60 of a Trust Unit foreach one (1) trust unit of Petrofund. An aggregate of approximately 70.7million 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 $129.6 million was distributed. As a result ofthe Petrofund Acquisition, Penn West acquired 70.9 MMbbl of light/mediumcrude oil and NGLs, 0.7 MMbbl of heavy oil and 279.3 Bcf of natural gas ona proved reserve basis, 93.8 MMbbl of light/medium crude oil and NGLs, 1.0 MMbblof heavy oil and 371.2 Bcf of natural gas on a proved plus probable reservebasis, and 352,600 net acres of undeveloped land. Penn West alsoassumed $610.4 million of bank indebtedness of Petrofund in connectionwith the Petrofund Acquisition.

 

*Acquisitionsand Dispositions*

* *

We completed property acquisitions, net ofdispositions, of $5.6 million in 2006. Other than the Petrofund Acquisitiondescribed above, we did not complete any corporate acquisitions in 2006.

 

***YearEnded December 31, 2007***

*** ***

*April 2007Asset Acquisition*

* *

On April 11, 2007, Penn West completed theacquisition (the “**April 2007 AssetAcquisition**”) of certain conventional oil and natural gas assets forcash consideration of approximately $329 million. The assets were locatedprimarily in the Province of Alberta and included assets situated within ornear Penn West’s Peace River oil sands project and its adjacent holdings in theRed Earth/Utikuma area. As a result of the acquisition, Penn West acquired 6.4MMbbl of light/medium crude oil and NGLs, 0.1 MMbbl of heavy oil and 15.6 Bcfof natural gas on a proved reserve basis, 8.1 MMbbl of light/medium crude oiland NGLs, 0.1 MMbbl of heavy oil and 21.9 Bcf of natural gas on a proved plusprobable reserve basis, and 190,000 net acres of undeveloped land. Theacquisition was financed using Penn West’s existing syndicated credit facilityand a new $250 million unsecured, demand credit facility.

 

10

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*PrivatePlacement of Notes*

* *

Effective May 31, 2007, PWPL completed theprivate placement of an aggregate of US$475 million principal amount of notes. Theprivate placement consisted of the issuance of US$160 million principal amountof 5.68 percent 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. Thenotes are unsecured and rank equally with Penn West’s bank credit facilities. Theproceeds of the notes were used to repay a portion of the indebtedness underPenn West’s bank credit facilities.

 

*Acquisitionsand Dispositions*

* *

In addition to the April 2007 Asset Acquisitiondescribed above, we completed property acquisitions, net of dispositions, of$92.7 million in 2007. We also completed one corporate acquisition for totalcash consideration of $21.2 million resulting in total acquisitions, net ofdispositions, of $442.9 million in 2007 (including the April 2007 AssetAcquisition).

 

***RecentDevelopments***

*** ***

*VaultAcquisition*

* *

Effective January 10, 2008, Penn West completedthe Vault Acquisition, pursuant to which Penn West acquired Vault on the basisof an exchange of 0.14 of a Trust Unit for each one (1) trust unit ofVault, 0.14 of a Trust Unit for each one (1) trust unit of Vault intowhich the Series A exchangeable shares of Vault Energy Inc. wereexchangeable, and a payment of $0.51 for each one (1) warrant to purchasea trust unit of Vault. An aggregate of approximately 5.6 million Trust Unitswere issued and an aggregate of approximately $768,111 was paid. As a result ofthe Vault Acquisition, and based on the Sproule Vault Report, Penn Westacquired 7.8 MMbbl of light/medium crude oil and NGLs and 49.5 Bcf of naturalgas on a proved reserve basis, and 10.1 MMbbl of light/medium crude oil andNGLs and 71.6 Bcf of natural gas on a proved plus probable reserve basis. PennWest also acquired 125,000 net acres of undeveloped land.

 

Penn West also assumed approximately $89 million ofbank indebtedness of Vault, $50 million principal amount of 7.2% Debenturesissued by Vault and $48.7 million principal amount of 8% 2005 Debentures issuedby Vault in connection with the Vault Acquisition. On March 5, 2008, PennWest repurchased for cancellation $23.8 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.

 

*CaneticAcquisition*

* *

Effective January 11, 2008, Penn West completedthe Canetic Acquisition, pursuant to which Penn West acquired Canetic on thebasis of an exchange of 0.515 of a Trust Unit for each one (1) trust unitof Canetic. An aggregate of approximately 124.3 million Trust Units wereissued. In addition, a special cash distribution in the amount of $0.09 pertrust unit of Canetic was made to holders of trust units of Canetic of recordat the close of business on January 10, 2008. An aggregate ofapproximately $21.7 million was distributed to Canetic unitholders on January 15,2008. As a result of the Canetic Acquisition, based on the Sproule CaneticReport, Penn West acquired 92.0 MMbbl of light/medium crude oil and NGLs, 15.1MMbbl of heavy oil and 403.2 Bcf of natural gas on a proved reserve basis and127.2 MMbbl of light/medium crude oil and NGLs, 19.4 MMbbl of heavy oil and597.9 Bcf of natural gas on a proved plus probable reserve basis. Penn Westalso acquired 774,000 net acres of undeveloped land. For detailed disclosure ofthe Sproule Canetic Report and other oil and gas information of Canetic inaccordance with NI 51-101, see Appendix B hereto.

 

Penn West assumed approximately $1.4 billion of bankindebtedness of Canetic, $17.8 million principal amount of 6.5% 2005 Debenturesissued by Canetic, $229.6 million principal amount of 6.5% 2006 Debenturesissued by Canetic, $8.0 million principal amount of 8% 2004 Debentures issuedby Canetic, and $5.6 million principal amount of 9.4% Debentures issued byCanetic in connection with the Canetic Acquisition.

 

In connection with the Canetic Acquisition, the Boardof Directors of PWPL was reconstituted to include eight members of PWPL’s thenexisting board and four members of Canetic’s then existing board. In addition,in connection with and following the completion of the Canetic Acquisition,PWPL’s management team was reconstituted to, among other things, 

 

11

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include certain former officers of Canetic. Fordetailed information regarding the current directors and officers of PWPL, see “CorporateGovernance – Directors and Officers” below.

 

Concurrent with the closing of the CaneticAcquisition, Penn West secured a $4 billion credit facility for a three-yearterm with a syndicate of 18 Canadian and international 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.

 

**Significant Acquisitions**

** **

There were no significant acquisitions completed byPenn West during the financial year ended December 31, 2007 for whichdisclosure was required under Part 8 of National Instrument 51-102. However,the completion of the Canetic Acquisition on January 11, 2008 constituteda significant acquisition for which disclosure was required under Part 8of National Instrument 51-102. For a description of the Canetic Acquisition,see “General Development of the Business – History and Development –Canetic Acquisition” above. Penn West has also filed a Form 51-102F4 –Business Acquisition Report in respect of the Canetic Acquisition.

 

**DESCRIPTION OF OUR BUSINESS**

** **

**Overview**

** **

Our principalundertaking is to issue Trust Units and to acquire and hold securities ofSubsidiaries, net profits interests, royalties, notes and other interests. Ourdirect and indirect Subsidiaries carry on the business of acquiring,developing, exploiting and holding interests in petroleum and natural gasproperties and assets related thereto. A portion of the funds flow from theassets is paid from PWPL and our other Operating Entities to us by way ofinterest and principal payments on the Internal Notes and payments under theNPI Agreements.

 

The Board ofDirectors may declare distributions payable to the Unitholders and allocate allor any of our income to the Unitholders. It is currently anticipated that theonly income we will receive will be from PWPL and our other Operating Entitiesby way of interest received on the principal amount of the Internal Notes andpayments pursuant to the NPIs. We make monthly cash distributions toUnitholders from this income after any expenses and any cash redemptions ofTrust Units.

 

Cashdistributions are made on or about the 15th day of each monthto Unitholders of record on or about the last calendar day of the immediatelypreceding month.

 

As at February 29,2008, we had approximately 1,850 employees and full time consultants.

 

**PWPL**

** **

PWPL is acorporation amalgamated and subsisting pursuant to the laws of Alberta. PWPL isactively engaged in the business of oil and natural gas exploitation,development, acquisition and production in Canada. The Trust is the soleshareholder of PWPL. The registered and head office of PWPL is located at 2200,425 – 1st Street S.W., Calgary, Alberta, T2P 3L8.

 

**Internal Notes**

** **

The InternalNotes evidence the indebtedness of PWPL and certain other Operating Entities toPenn West. The Internal Notes are payable on demand, are unsecured, and aresubordinated to senior indebtedness and bear interest at rates ranging from sixpercent per annum to 13 percent per annum and require principal payments atdates ranging from May 31, 2017 to January 1, 2019.

 

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**NPIs**

** **

TheTrust is a party to NPI Agreements with PWPL and certain other OperatingEntities pursuant to which we have the right to receive the NPIs on petroleumand natural gas rights held by PWPL and the other Operating Entities from timeto 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 generally include capital expenditures, royalties,operating costs and certain interest expenses related to oil and gas activities.The term of the agreements is for as long as there are petroleum and naturalgas rights to which the NPIs apply.

 

**Pro Forma Reserves Data ofPenn West, Canetic and Vault**

** **

The pro forma reserves data set forth below isan aggregate roll-up of Penn West’s reserves data, Canetic’s reserves data andVault’s reserves data. Penn West’s reserves data is based upon an evaluationprepared by GLJ with an effective date of December 31, 2007 contained inthe GLJ Report dated February 20, 2008. Canetic’s reserves data is basedon an evaluation prepared by Sproule with an effective date of December 31,2007 contained in the Sproule Canetic Report dated March 3, 2008. Vault’sreserves data is based upon an evaluation prepared by Sproule with an effectivedate of December 31, 2007 contained in the Sproule Vault Report dated March 3,2008. Each of the aforementioned reports was prepared in accordance withNI 51-101.

 

The pro forma reserves data summarizes PennWest’s, Canetic’s and Vault’s oil, natural gas liquid and natural gas reservesand net present values of future net revenue from these reserves using forecastprices and costs, not including the effect of any hedging activities, as at December 31,2007 assuming that all reserves were held by Penn West at that time. The sameforecast price and cost assumptions were used in the GLJ Report, the SprouleCanetic Report and the Sproule Vault Report. For information respecting theforecast price and cost assumptions used and other relevant information, see “Notesto Reserves Data Tables” in Appendix A-3 Statement of Reserves Data – Penn WestEnergy Trust and in Appendix B-3 Statement of Reserves Data – Canetic ResourcesTrust.

 

See Appendices A-1, A-2 and A-3 for complete NI51-101 oil and gas reserves disclosure for Penn West on a “stand-alone” basisas at December 31, 2007. See Appendices B-1, B-2 and B-3 for select  NI 51-101 oil and gas reserves disclosure forCanetic on a “stand-alone” basis as at December 31, 2007. See “GeneralDevelopment of the Business – History and Development – Vault Acquisition” forcertain summary information in respect of Vault’s oil and gas reserves as at December 31,2007 that is derived from the Sproule Vault Report.

 

**The GLJ Report, the Sproule CaneticReport and the Sproule Vault Report do not take into account the new Albertaroyalty regime released on October 25, 2007 titled *“The New Royalty Framework”*, which isscheduled to take effect on January 1, 2009, because sufficient detailsare not yet available for it to be taken into account. See “Risk Factors – NewAlberta Royalty Regime”.**

 

All of the pro forma reserves are in Canadaand, specifically, in the provinces of Alberta, British Columbia, Saskatchewanand Manitoba, other than some minor interests in the United States that PennWest acquired from Canetic pursuant to the Canetic Acquisition.

 

**Itshould not be assumed that the estimates of future net revenues presented inthe tables below represent the fair market value of the reserves. There is noassurance that the forecast prices and costs assumptions will be attained andvariances could be material. The recovery and reserves estimates of crude oil,natural gas liquids and natural gas reserves provided herein are estimates onlyand there is no guarantee that the estimated reserves will be recovered. Actualcrude oil, natural gas and natural gas liquid reserves may be greater than orless than the estimates provided herein. For more information as to the risksinvolved, see “Risk Factors – Reserve and Resource Estimates” and “Risk Factors– Volatility of Oil and Natural Gas Prices”.**

 

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PRO FORMA SUMMARY OFPENN WEST, CANETIC AND VAULT OIL AND GAS RESERVESas of December 31, 2007FORECAST PRICES AND COSTS

 
| ** **                 | ** ** | **RESERVES**             | ** ** |
|----------------------------|------------|--------------------------|------------|
| ** **                 | ** ** | **LIGHT AND MEDIUM OIL** | ** ** | **HEAVY OIL** | ** ** |
| **RESERVES CATEGORY**      | ** ** | **Gross  (MMbbl)**       | ** ** | **Net  (MMbbl)** | ** ** | **Gross  (MMbbl)** | ** ** | **Net  (MMbbl)** | ** ** |
|                       |       |                     |       |   |   |   |   |   |   |
| PROVED                     |       |                     |       |   |   |   |   |   |   |
| Developed Producing        |       | 233.5                    |       | 212.0 |   | 56.1 |   | 50.8 |   |
| Developed Non-Producing    |       | 5.3                      |       | 5.0 |   | 3.0 |   | 2.6 |   |
| Undeveloped                |       | 38.7                     |       | 34.8 |   | 1.5 |   | 1.4 |   |
| TOTAL PROVED               |       | 277.5                    |       | 251.8 |   | 60.6 |   | 54.7 |   |
|                       |       |                     |       |   |   |   |   |   |   |
| PROBABLE                   |       | 89.7                     |       | 80.3 |   | 20.6 |   | 18.3 |   |
| TOTAL PROVED PLUS PROBABLE |       | 367.2                    |       | 332.0 |   | 81.2 |   | 73.1 |   |

 
| ** **                 | ** ** | **RESERVES**     | ** ** |
|----------------------------|------------|------------------|------------|
| ** **                 | ** ** | **NATURAL GAS**  | ** ** | **NATURAL GAS LIQUIDS** | ** ** |
| **RESERVES CATEGORY**      | ** ** | **Gross  (Bcf)** | ** ** | **Net  (Bcf)** | ** ** | **Gross  (MMbbl)** | ** ** | **Net  (MMbbl)** | ** ** |
|                       |       |             |       |   |   |   |   |   |   |
| PROVED                     |       |             |       |   |   |   |   |   |   |
| Developed Producing        |       | 1,027.2          |       | 830.4 |   | 27.1 |   | 19.0 |   |
| Developed Non-Producing    |       | 66.3             |       | 52.4 |   | 1.4 |   | 0.9 |   |
| Undeveloped                |       | 62.2             |       | 49.3 |   | 1.4 |   | 0.9 |   |
| TOTAL PROVED               |       | 1,155.7          |       | 932.1 |   | 29.9 |   | 20.9 |   |
|                       |       |             |       |   |   |   |   |   |   |
| PROBABLE                   |       | 414.6            |       | 333.0 |   | 10.2 |   | 7.3 |   |
| TOTAL PROVED PLUS PROBABLE |       | 1,570.3          |       | 1,265.1 |   | 40.1 |   | 28.2 |   |

 
| ** **                 | ** ** | **RESERVES**             | ** ** |
|----------------------------|------------|--------------------------|------------|
| ** **                 | ** ** | **TOTAL OIL EQUIVALENT** | ** ** |
| **RESERVES CATEGORY**      | ** ** | **Gross  (MMboe)**       | ** ** | **Net  (MMboe)** | ** ** |
|                       |       |                     |       |   |   |
| PROVED                     |       |                     |       |   |   |
| Developed Producing        |       | 487.9                    |       | 420.1 |   |
| Developed Non-Producing    |       | 20.8                     |       | 17.3 |   |
| Undeveloped                |       | 52.0                     |       | 45.4 |   |
| TOTAL PROVED               |       | 560.6                    |       | 482.8 |   |
|                       |       |                     |       |   |   |
| PROBABLE                   |       | 189.7                    |       | 161.4 |   |
| TOTAL PROVED PLUS PROBABLE |       | 750.2                    |       | 644.2 |   |
|                            |            |                          |            |  |  |  |

 

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PRO FORMANET PRESENT VALUES OF FUTURE NET REVENUE OF PENN WEST, CANETIC AND VAULTBEFORE INCOME TAXES DISCOUNTED AT (%/year)

FORECAST PRICES AND COSTS(1)

 
| **RESERVES CATEGORY** | ** ** | **0%  (MM$)** | ** ** | **5%  (MM$)** | ** ** | **10%  (MM$)** | ** ** | **15%  (MM$)** | ** ** | **20%  (MM$)** | ** ** |
|----------------------------|------------|---------------|------------|---------------|------------|----------------|------------|----------------|------------|----------------|------------|
|                       |       |          |       |          |       |           |       |           |       |           |       |
| PROVED                     |       |          |       |          |       |           |       |           |       |           |       |
| Developed Producing        |       | 16,693        |       | 11,825        |       | 9,424          |       | 7,965          |       | 6,969          |       |
| Developed Non-Producing    |       | 669           |       | 445           |       | 339            |       | 275            |       | 231            |       |
| Undeveloped                |       | 2,053         |       | 1,102         |       | 679            |       | 451            |       | 313            |       |
| TOTAL PROVED               |       | 19,415        |       | 13,372        |       | 10,442         |       | 8,691          |       | 7,512          |       |
|                       |       |          |       |          |       |           |       |           |       |           |       |
| PROBABLE                   |       | 7,374         |       | 3,713         |       | 2,333          |       | 1,652          |       | 1,256          |       |
|                       |       |          |       |          |       |           |       |           |       |           |       |
| TOTAL PROVED PLUS PROBABLE |       | 26,790        |       | 17,085        |       | 12,774         |       | 10,342         |       | 8,768          |       |

 

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Note:

(1)           Management of PWPL has estimated that the impact ofAlberta’s Proposed Royalty Regime, in the form currently proposed, is todecrease the pro forma net present values of future net revenue before incometaxes by approximately 3 percent to 4 percent using a 10 percent discount rateand using the forecast prices set forth in this Annual Information Form.

 

PRO FORMANET PRESENT VALUES OF FUTURE NET REVENUE OF PENN WEST, CANETIC AND VAULTAFTER INCOME TAXES DISCOUNTED AT (%/year)

FORECAST PRICES AND COSTS

 
| **RESERVES CATEGORY**      | ** ** | **0%  (MM$)** | ** ** | **5%  (MM$)** | ** ** | **10%  (MM$)** | ** ** | **15%  (MM$)** | ** ** | **20%  (MM$)** | ** ** |
|----------------------------|------------|---------------|------------|---------------|------------|----------------|------------|----------------|------------|----------------|------------|
| PROVED                     |       |          |       |          |       |           |       |           |       |           |       |
| Developed Producing        |       | 15,298        |       | 11,185        |       | 9,071          |       | 7,749          |       | 6,829          |       |
| Developed Non-Producing    |       | 543           |       | 376           |       | 293            |       | 242            |       | 207            |       |
| Undeveloped                |       | 1,614         |       | 891           |       | 560            |       | 377            |       | 263            |       |
| TOTAL PROVED               |       | 17,455        |       | 12,451        |       | 9,924          |       | 8,368          |       | 7,299          |       |
|                       |       |          |       |          |       |           |       |           |       |           |       |
| PROBABLE                   |       | 5,612         |       | 2,909         |       | 1,875          |       | 1,359          |       | 1,054          |       |
|                       |       |          |       |          |       |           |       |           |       |           |       |
| TOTAL PROVED PLUS PROBABLE |       | 23,068        |       | 15,360        |       | 11,798         |       | 9,727          |       | 8,353          |       |

** **

**CAPITALIZATION OF PWPL**

** **

**Common Shares**

** **

PWPL has authorized for issuance an unlimited number of commonshares.  We own all of the issued commonshares.  The voting of such shares isdelegated to the Board of Directors under the Trust Indenture other than:  (i) any sale, lease or other dispositionof, or any interest in, all or substantially all of our assets, except inconjunction with an internal reorganization of our direct or indirect assets asa result of which we have the same, or substantially similar, interest, whetherdirect or indirect, in the assets as the interest, whether direct or indirect,that it had prior to the reorganization; (ii) any statutory amalgamationof PWPL with any other entity, except in conjunction with an internalreorganization as referred to in paragraph (i) above; (iii) anystatutory arrangement involving PWPL, except in conjunction with an internalreorganization as referred to in paragraph (i) above; (iv) anyamendment to the articles of PWPL to increase or decrease the minimum ormaximum number of directors; or (v) any material amendment to the articlesof PWPL to change the authorized share capital or amend the 

 

15

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rights, privileges, restrictions and conditions attaching to any classof PWPL’s shares in a manner which may be prejudicial to us, without theapproval of the Unitholders by special resolution at a meeting of Unitholderscalled for that purpose.

 

The holders of common shares are entitled to receive notice of and toattend all meetings of the shareholders of PWPL and to one vote at suchmeetings.  The holders of common shareswill be, at the discretion of the Board of Directors and subject to applicablelegal restrictions, entitled to receive any dividends declared by the Board ofDirectors on the common shares. The holders of common shares will be entitledto share equally in any distribution of the assets of PWPL upon theliquidation, dissolution, bankruptcy or winding-up of PWPL or otherdistribution of its assets among its shareholders for the purpose of winding-upits affairs subject to the rights, privileges, restrictions and conditionsattaching to any other shares having priority over the common shares.

 

**Preferred Shares**

** **

PWPL is authorized to issue an unlimitednumber of preferred shares in series. Before any shares of a particular series are issued, the Board ofDirectors shall, by resolution, fix the number of shares that will form suchseries and shall, subject to the limitations set out herein, by resolution fixthe designation, rights, privileges, restrictions and conditions to be attachedto the preferred shares of such series. The preferred shares of each series shall rank on a parity with thepreferred shares of every other series with respect to accumulated dividendsand return of capital.  The preferredshares are entitled to a preference over the common shares and over any othershares 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 ofDirectors has authorized one series of preferred shares, being the firstpreferred shares series A (the “**Series APreferred Shares**”).  Onethousand Series A Preferred Shares have been authorized for issuance.  Holders of Series A Preferred Shares areentitled to receive preferential cash dividends in such amounts as may bedeclared by the Board of Directors.  Thepayment of such dividends is in priority to dividends on the common shares ofPWPL and all other shares ranking junior to the Series A Preferred Shareswith respect to the payment of dividends. PWPL has the right to redeem at any time all, or from time to time anypart, of the then outstanding Series A Preferred Shares at a price pershare equal to $1,000, together with all accrued and unpaid dividends thereonup to the date fixed for redemption. Each registered holder of Series A Preferred Shares is entitled torequire PWPL to retract at any time any Series A Preferred Shares tenderedat a price per share equal to $1,000, together with all accrued and unpaiddividends thereon up to the retraction date. In the event of the liquidation, dissolution or winding-up of PWPL orother distribution of the assets of PWPL among its shareholders for the purposeof winding-up its affairs, the holders of Series A Preferred Shares areentitled to receive an amount per Series A Preferred Share equal to $1,000per share, together with any accrued and unpaid dividends to the date ofcommencement of such event, to be paid all such money before any money shall bepaid or property or assets distributed to the holders of any common shares ofPWPL or other shares in the capital of PWPL ranking junior to the Series APreferred Shares with respect to return of capital.  After payment of the aforementioned amount,the Series A Preferred Shares shall not be entitled to share in anyfurther distribution of the property or assets of PWPL.  So long as any Series A Preferred Sharesare outstanding PWPL may not, without the approval of the holders of the Series APreferred Shares, take certain actions unless all dividends which have beendeclared have been paid or set apart for payment.  Subject to applicable law, the holders of theSeries A Preferred Shares are not entitled as such to any voting rights orto receive notice of or to attend any meeting of the shareholders of PWPL or tovote at any such meeting, except for meetings at which holders of a specifiedclass or series of shares of PWPL are entitled or required to vote separatelyas a class or series pursuant to the provisions of the ABCA.

 

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

 

**Borrowing**

** **

Weborrow funds from time to time to finance the purchase of properties, forcapital expenditures or for other financial obligations or expenditures inrespect of properties held by us or for working capital purposes.

 

Certaindebt service charges on borrowed funds attributable to our properties will bededucted in computing income under the NPIs. Capital expenditures and any debt repayment will be scheduled tominimize any income tax payable by PWPL.

 

16

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**INFORMATION RELATING TO PENN WEST**

** **

**TrustUnits**

** **

Anunlimited number of Trust Units may be issued pursuant to the TrustIndenture.  The Trust Units representequal undivided beneficial interests in Penn West. All Trust Units shareequally in all distributions made by us and all Trust Units carry equal votingrights at meetings of Unitholders. No Unitholder will be liable to pay anyfurther calls or assessments in respect of the Trust Units. No conversion,retraction or pre-emptive rights attach to the Trust Units.

 

Asat March 26, 2008, approximately 374.2 million Trust Units were outstanding,approximately 6.3 million Trust Units were reserved for issuance on conversionof the Convertible Debentures and approximately 25.3 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).

 

**SpecialVoting Units**

** **

TheTrust Indenture also provides for the issuance of special voting units andwhich are entitled to such number of votes at meetings of Unitholders and any otherrights or limitations prescribed by the Board of Directors when the Board ofDirectors authorizes issuing such special voting units. The Trust Units and thespecial voting units vote together as a single class on all matters. In theevent of our liquidation, dissolution or winding-up, the holders of specialvoting units will not be entitled to receive any of our assets available fordistribution to our Unitholders.  Theholders of special voting units will not be entitled to receive dividends orother distributions from us.

 

**ConvertibleDebentures**

** **

PennWest has six series of convertible debentures outstanding, the 6.5% 2005Debentures, the 6.5% 2006 Debentures, the 7.2% Debentures, the 8% 2004Debentures, the 8% 2005 Debentures and the 9.4% Debentures.  The 7.2% Debentures and the 8% 2005Debentures were assumed by Penn West pursuant to the Vault Acquisition, whichclosed on January 10, 2008.  The 6.5%2005 Debentures, the 6.5% 2006 Debentures, the 8% 2004 Debentures and the 9.4%Debentures were assumed by Penn West pursuant to the Canetic Acquisition, whichclosed on January 11, 2008.  Thefollowing is a summary of the material attributes and characteristics of theConvertible Debentures.

 

The6.5% 2006 Debentures were originally issued in the aggregate principal amountof $230 million and $229.6 million principal amount was outstanding at March 26,2008.  The 6.5% 2006 Debentures mature onDecember 31, 2011.

 

The8% 2004 Debentures were originally issued in the aggregate principal amount of$75 million and approximately $8.0 million principal amount was outstanding at March 26,2008.  The 8% 2004 Debentures mature on August 31,2009.

 

The6.5% 2005 Debentures were originally issued in the aggregate principal amountof $60 million and approximately $17.8 million principal amount was outstandingat March 26, 2008.  The 6.5% 2005Debentures mature on July 31, 2010.

 

The9.4% Debentures were originally issued in the aggregate principal amount of $50million and approximately $5.6 million principal amount was outstanding at March 26,2008.  The 9.4% Debentures mature on July 31,2008.

 

The8% 2005 Debentures were originally issued in the aggregate principal amount of$55 million and approximately $48.7 million principal amount was outstanding atMarch 26, 2008.  The 8% 2005Debentures mature on June 30, 2010.

 

The7.2% Debentures were originally issued in the aggregate principal amount of $50million and approximately $26.2 million principal amount was outstanding at March 26,2008.  The 7.2% Debentures mature on May 31,2011.

 

***Terms of Convertible Debentures***

*** ***

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.  The 8% 2004 Debenturesbear interest from the date of issue at 8% per annum, which is payablesemi-annually in arrears on February 28 and August 31 in eachyear.  The 6.5% 2005 Debentures bearinterest from the date of issue at 6.5% per annum, which is payablesemi-annually in arrears on January 31 and July 31 in 

 

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eachyear.  The 9.4% Debentures bear interestfrom the date of issue at 9.4% per annum, which is payable semi-annually inarrears on January 31 and July 31 in each year.  The 8% 2005 Debentures bear interest from thedate of issue at 8% per annum, which is payable semi-annually in arrears on June 30and December 31 in each year.  The7.2% Debentures bear interest from the date of issue at 7.2% per annum, whichis payable semi-annually in arrears on May 31 and November 30 in eachyear.

 

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 tosecure any indebtedness.

 

***Conversion Privilege***

*** ***

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.

 

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.

 

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.

 

The9.4% 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, 2008 and the last business day immediately precedingthe date specified by Penn West for redemption of the 9.4% Debentures, at aconversion price of $31.1068 per Trust Unit, being a conversion rate ofapproximately 32.1473 Trust Units for each $1,000 principal amount of 9.4%Debentures.

 

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.

 

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.

 

***Redemption and Purchase***

*** ***

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 

 

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December 31,2010 and before maturity (each a “**6.5% 2006Redemption Price**”) in each case, plus accrued and unpaid interestthereon, if any.

 

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 $1,050 per 8% 2004 Debenture on or before August 31,2008 and at a redemption price of $1,025 per 8% 2004 Debenture after August 31,2008 and before maturity (each an “**8% 2004Redemption Price**”), in each case, plus accrued and unpaid interestthereon, if any.

 

The6.5% 2005 Debentures are not redeemable on or before July 31, 2008.  The Trust may, on not more than 60 days andnot less than 30 days prior notice, redeem the 6.5% 2005 Debentures at aredemption price of $1,050 per 6.5% 2005 Debenture after July 31, 2008,and on or before July 31, 2009, and at a price of $1,025 per 6.5% 2005Debenture after July 31, 2009 and before July 31, 2010 (each a “**6.5% 2005 Redemption Price**”), plus accruedand unpaid interest thereon, if any.

 

TheTrust may, on not more than 60 days and not less than 30 days prior notice,redeem the 9.4% Debentures at a redemption price of $1,025 per 9.4% Debenturebefore July 31, 2008 (each a “**9.4%Redemption Price**”), plus accrued and unpaid interest thereon, ifany.

 

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.

 

The8% 2005 Debentures are not redeemable on or before June 30, 2008.  After June 30, 2008 and prior to maturity,debenture holders may cause the Trust to redeem the 8% 2005 Debentures in wholeor in part from time to time on not more than 60 days and not less than 30 daysprior notice, at a redemption price of $1,050 per 8% 2005 Debenture after June 30,2008 and before July 1, 2009, and a redemption price of $1,025 per 8% 2005Debenture 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 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 orrealization of security or otherwise in any manner whatsoever) on account ofindebtedness represented by the Convertible Debentures (a) in a mannerinconsistent with the terms (as they exist on the date of issue) of theConvertible Debentures or (b) at any time when an event of default hasoccurred under the Senior Indebtedness and is continuing and the notice of suchevent of default has been given by or on behalf of the holders of SeniorIndebtedness to the Trust, unless the Senior Indebtedness has been repaid infull.

 

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 US$475 million principal amount of 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 66 2/3 percent or more of the Trust Units (a “**Change of Control**”), the Trust is requiredto make an offer in writing to purchase all of the Convertible Debentures thenoutstanding (the “**Debenture Offer**”),at a price equal to 101 percent of the principal amount thereof plusaccrued and unpaid interest (the “**DebentureOffer 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, the6.5% 2005 Debentures and the 9.4% Debentures (but, for greater certainty, notthe 7.2% Debentures or the 8% 2005 Debentures) (the “**Interest Obligation**”), on the date it is payable under theapplicable Debenture Indenture (an “**InterestPayment Date**”), by delivering sufficient Trust Units to theDebenture Trustee to satisfy all or the part, as the case may be, of theInterest Obligation 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 proceedsreceived from such permitted government securities, together with any proceedsfrom 

 

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thesale 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 applicable ConvertibleDebentures 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 principal amount of the Convertible Debenturespresent at the meeting or represented by proxy, or rendered by instruments inwriting signed by the holders of not less than 662/3 percent of the principal amount of the Convertible Debentures thenoutstanding. In certain cases, the modification will, instead or in addition,require assent by the holders of the required percentage of ConvertibleDebentures of each particularly affected series.

 

***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 the Total Market Capitalization of theTrust immediately after the issuance of such additional ConvertibleDebenture.  “**Total Market Capitalization**” is defined in the DebentureIndentures as the total principal amount of all issued and outstandingConvertible Debentures of the Trust which are convertible at the option of theholder into Trust Units plus the amount obtained by multiplying the number ofissued and outstanding Trust Units by the Current Market Price of the TrustUnits 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 withsatisfactory evidence that they are not Non-Residents within such period, theDebenture Trustee may on behalf of such holder of Convertible Debentures, and,in the interim, shall suspend the rights attached to such ConvertibleDebentures.  Upon such sale the affectedholders shall cease to be holders of Convertible Debentures, and their rightsshall be limited 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-entryonly” form and must be purchased or transferred through a participant in thedepository service of CDS & Co. The Convertible Debentures (other than the 8% 2005 Debentures) areevidenced 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 and 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. Substantive amendments to the Trust Indenture,including early termination of the Trust and the sale or transfer of ourproperty as an entirety or substantially as an entirety, requires approval byspecial 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 has been filedon 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 and 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 good faith and in our bestinterests and in the best interest of the Unitholders and, in connectiontherewith, shall exercise that degree of care, diligence and skill that areasonably prudent trustee would exercise in comparable circumstances.

 

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The initial term of the Trustee’s appointment is until the third annualmeeting of Unitholders.  The Unitholdersshall, at the third annual meeting of the Unitholders, re-appoint, or appoint asuccessor to the Trustee for an additional three year term, and thereafter, theUnitholders are required to re-appoint or appoint a successor to the Trustee atthe annual meeting of Unitholders three years following the re-appointment orappointment of the successor to the Trustee. The Trustee may also be removed by special resolution of theUnitholders.  Such resignation or removalbecomes effective upon the acceptance or appointment of a successor trustee.

 

PWPLpresently administers us on behalf of the Trustee.  PWPL, on behalf of the Trustee, keeps suchbooks and records as are necessary for the proper recording of our businesstransactions.

 

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 our assets for any liabilities relating to anytaxes or other government charges imposed upon the Trustee or in consequence ofits performance of its duties unless such liabilities arise principally anddirectly out of gross negligence, wilful default or fraud of the Trustee, buthas no additional recourse against Unitholders. In addition, the Trust Indenture contains other customary provisionslimiting 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 us 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 our auditors and to electall the members of the Board of Directors.

 

***Our Management***

*** ***

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

 

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 ourbest interests and the best interests of the Unitholders and, in connectiontherewith, shall exercise that degree of care, diligence and skill that areasonable person would exercise in comparable circumstances.

 

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

*** ***

Inorder for us to maintain our status as a mutual fund trust under the Tax Act,we must not be established or maintained primarily for the benefit ofNon-Residents unless we satisfy the requirements of certain exceptions. TheTrust Indenture provides that Penn West will use its best commercial efforts tomaintain its status 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 

 

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substantiallyall” of the trust’s property consists of property other than taxable Canadianproperty (the “**TCP Exception**”).  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.  See “RiskFactors – Non-Resident Ownership of Trust Units”.

 

***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 average ofthe highest and lowest prices for each of the trading days on which there was atrade; and provided further that if there was trading on the applicableexchange or market for fewer than five of the 10 trading days, the market priceshall be the simple average of the following prices established for each of the10 trading days: the average of the last bid and last ask prices for each dayon which there was no trading; the closing price of the Trust Units for eachday that there was trading if the exchange or market provides a closing price;and the average of the highest and lowest prices of the Trust Units for eachday that there was trading, if the market provides only the highest and lowestprices of Trust Units traded on a particular day.  The closing market price shall be: an amountequal to the closing price of the Trust Units if there was a trade on the date;an amount equal to the average of the highest and lowest prices of the TrustUnits if there was trading and the exchange or other market provides only thehighest and lowest prices of Trust Units traded on a particular day; and theaverage of the last bid and last ask prices if there was no trading on thedate.

 

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 sowaived, the Market Redemption Price payable by the Trust in respect of TrustUnits tendered for redemption in such calendar month shall be paid on the lastday of the calendar month following such month by the Trust distributingredemption notes of PWPL to the Unitholders who exercised the right ofredemption.

 

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 directors of PWPLin 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 andregistered education savings plans.

 

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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 our assets, pay, retire, discharge ormake provision for some or all of our obligations and then distribute theremaining proceeds of sale to Unitholders.

 

***Reporting to Unitholders***

*** ***

Ourfinancial statements will be audited annually by an independent recognized firmof chartered accountants. Our audited financial statements, together with thereport of such chartered accountants, will be mailed by the Trustee toUnitholders if previously requested and, if previously requested, the unauditedinterim financial statements will be mailed to Unitholders within the periodsprescribed by securities legislation. Our 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 whichwe will vote our common shares in PWPL at all meetings in respect of mattersrelating to the election of the directors of PWPL, approving its financialstatements and appointing auditors of PWPL who shall be the same as ourauditors.  Prior to us voting our commonshares in PWPL in respect of such matters, each Unitholder is entitled to votein respect of the matter on the basis of one vote per Trust Unit held, and weare required to vote our common shares in PWPL in accordance with the result ofthe vote of Unitholders.

 

**DecisionMaking**

** **

TheBoard of Directors has a mandate to supervise the management of our businessand affairs, PWPL and our other direct or indirect Subsidiaries and to act witha view to our best interest.  The Boardof Directors’ mandate includes:  (i) anyoffering of securities; (ii) ensuring compliance with all applicable laws,including in relation to an offering of securities; (iii) all mattersrelating to the content of any documents relating to an offering of securities,the accuracy of the disclosure contained therein, and the certificationthereof; (iv) all matters concerning the terms of, and amendment from timeto time of, material contracts; (v) all matters concerning anysubscription agreement or underwriting or agency agreement providing for thesale or issue of Trust Units or securities convertible for or exchangeable intoTrust Units or rights to acquire Trust Units; (vi) all matters relating tothe redemption of Trust Units; (vii) all matters relating to the votingrights on any investments; (viii) all matters relating to the specificpowers and authorities as set forth in the Trust Indenture; (ix) theadoption of a Unitholder rights plan and other miscellaneous matters relatingto the maximization of Unitholder value; and (x) all matters relating toamending PWPL’s articles to create exchangeable shares.  The Board of Directors holds regularlyscheduled meetings at least quarterly to review the business and affairs of ourSubsidiaries and make any necessary decisions relating thereto.

 

25

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The Trust Indenture gives to theBoard of Directors the authority to exercise the rights, powers and privilegesfor all matters relating to the maximization of Unitholder value in the contextof a take-over bid (an “**Offer**”)including any Unitholder rights protection plan, any defensive action to anOffer, any directors circular in response to an Offer, any regulatory or courtproceeding relating to an Offer and any related or ancillary matter.

 

**Distributions and Distribution Policy**

** **

Cash distributions are made onthe 15th day (or if such date is not a business day, on thepreceding business day) following the end of each calendar month to Unitholdersof record on the last business day of each such calendar month or such otherdate as determined from time to time by the Trustee.

 

The Board of Directors on ourbehalf reviews the distribution policy from time to time. The actual amountdistributed will be dependent on various factors, including the commodity priceenvironment, and is at the discretion of the Board of Directors of PWPL. Thecurrent distribution policy targets the use of approximately 60 percent to70 percent of funds flow for distribution to Unitholders. Depending uponvarious factors, including commodity prices and the size of Penn West’s capitalbudget, it is expected that approximately 30 percent to 40 percent offunds flow will fund all or a portion of Penn West’s annual capital expenditureprogram, including exploration, exploitation expenditures and minor propertyacquisitions, but excluding major acquisitions.

 

Distributions are normallyannounced on a monthly basis in the context of prevailing and anticipatedcommodity prices. During periods of volatile commodity prices, we may vary thedistribution rate monthly.

 

Pursuant to the provisions ofthe Trust Indenture all taxable income earned by Penn West in a fiscal year,not previously distributed in that fiscal year, must be distributed toUnitholders of record on December 31. This excess income, if any, will beallocated to 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 tradesTrust Units in this period they will be allocated such income but will disposeof their right to receive the cash or Trust Units comprising such adistribution.

 

The credit agreement governingPenn West’s $4 billion syndicated credit facility and the note purchaseagreement governing PWPL’s US$475 million principal amount of notes bothcontain provisions which restrict the ability of PWPL to pay Penn West underthe NPIs and interest on the Internal Notes and thereby may restrict distributionsto Unitholders in the event of the occurrence of certain events of default. Forfurther information regarding the credit agreement governing our syndicatedcredit facility, reference is made to note 5 of our consolidated financialstatements for the year ended December 31, 2007. For further informationregarding the note purchase agreement governing PWPL’s notes, reference is madeto note 5 of our consolidated financial statements for the year endedDecember 31, 2007. Note 5 of our consolidated financial statementsfor the year ended December 31, 2007 is incorporated by reference in thisAnnual Information Form. Our consolidated financial statements for the yearended December 31, 2007 are filed on SEDAR at www.sedar.com. Foradditional information, see “Risk Factors – Debt Service”.

 

**Directors and Executive Officers of PWPL**

** **

The following table sets forththe name, province/state and country of residence and positions and officesheld for each of the directors and executive officers of PWPL as of February29, 2008 following completion of the Canetic Acquisition, together with theirprincipal occupations during the last five years. The directors of PWPL willhold office until the next annual meeting of Unitholders or until theirrespective successors have been duly elected or appointed.

 
| **Name, Province/State and  Country of Residence** | ** ** | **Positions and Offices Held** | ** ** | **Principal Occupations  during the Five Preceding Years**                                                          |
|----------------------------------------------------|------------|--------------------------------|------------|---------------------------------------------------------------------------------------------------------------------|
| James E. Allard(1)  Alberta, Canada                |       | Director since 2006            |       | Independent director and  business advisor. Also, a member of the Alberta Securities Commission from  1999 to 2005. |

 

26

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| **Name, Province/State and  Country of Residence** | ** ** | **Positions and Offices Held**                                                    | ** ** | **Principal Occupations  during the Five Preceding Years**                                                                                                                                                                                                                                                                                                                                                                            |
|----------------------------------------------------|------------|-----------------------------------------------------------------------------------|------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                                               |       |                                                                              |       |                                                                                                                                                                                                                                                                                                                                                                                                                                  |
| William E. Andrew  Alberta, Canada                 |       | Chief Executive Officer  Director since 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. Also, a corporate director of a number of  companies, including a director of the administrator of Canetic from its  inception in January 2006 until January 2008. |
|                                               |       |                                                                              |       |                                                                                                                                                                                                                                                                                                                                                                                                                                  |
| George H. Brookman(2)(4)(5)  Alberta, Canada       |       | Director since 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 and director since 1995                       |       | Senior Partner, Burnet,  Duckworth & Palmer LLP (barristers and solicitors).                                                                                                                                                                                                                                                                                                                                                      |
|                                               |       |                                                                              |       |                                                                                                                                                                                                                                                                                                                                                                                                                                  |
| Daryl Gilbert(3)(5)  Alberta, Canada               |       | Director since  January 11, 2008                                             |       | President and Chief Executive  Officer of GLJ Petroleum Consultants Ltd. (formerly Gilbert Laustsen Jung  Associates Ltd.) (an engineering consulting firm) until 2005. Director of the  administrator of Canetic from its inception in January 2006 until January  2008.  Independent business consultant  since 2005.                                                                                                          |
|                                               |       |                                                                              |       |                                                                                                                                                                                                                                                                                                                                                                                                                                  |
| Jack C. Lee  Alberta, Canada                       |       | Vice Chairman of the Board of  Directors and director since January 11, 2008 |       | Corporate director since  October 2002, including Chairman of the Canetic Board of Directors from its  inception in January 2006 until January 2008. Prior thereto, President and  Chief Executive Officer of Acclaim.                                                                                                                                                                                                                |
|                                               |       |                                                                              |       |                                                                                                                                                                                                                                                                                                                                                                                                                                  |
| Shirley A. McClellan(1)(4)(5)  Alberta, Canada     |       | Director since 2007                                                               |       | 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.                                                                                                                                                                                                                                             |
|                                               |       |                                                                              |       |                                                                                                                                                                                                                                                                                                                                                                                                                                  |
| Thomas E. Phillips(3)  Alberta, Canada             |       | Director since 1995                                                               |       | President, Newhaven  Investments Inc. (a private oil and gas company).                                                                                                                                                                                                                                                                                                                                                                |
|                                               |       |                                                                              |       |                                                                                                                                                                                                                                                                                                                                                                                                                                  |
| Frank Potter(1)(4)  Ontario, Canada                |       | Director since 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) and President and Chief  Executive Officer of XPRONET Resources Inc. (a private oil and gas company).  Also, a director of the administrator of Canetic from its inception in  January 2006 until January 2008.                                                                                                                                  |
|                                               |       |                                                                              |       |                                                                                                                                                                                                                                                                                                                                                                                                                                  |
| James C. Smith(1)(2)(3)  Alberta, Canada           |       | Director since 2005                                                               |       | Independent director and  consultant to a number of public and private oil and gas companies.                                                                                                                                                                                                                                                                                                                                         |

 

27

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| **Name, Province/State and  Country of Residence** | ** ** | **Positions and Offices Held**                                    | ** ** | **Principal Occupations  during the Five Preceding Years**                                                                                                                                                                                                                                                                                                                                                                                                                                 |
|----------------------------------------------------|------------|-------------------------------------------------------------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| ** **                                         | ** ** | ** **                                                        | ** ** | ** **                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 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,  Operations and Corporate Development   |       | 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. Prior thereto, Vice President, Production of PWPL.                                                                                       |
|                                               |       |                                                              |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| Mark P. Fitzgerald  Alberta, Canada                |       | Senior Vice President,  Engineering                               |       | 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). Prior thereto, worked in asset management, acquisitions  and mergers for Dominion Energy Canada Ltd. (an oil and gas company). |
|                                               |       |                                                              |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| Thane A.E. Jensen  Alberta, Canada                 |       | Senior Vice President,  Exploration and Development               |       | Senior Vice President,  Exploration and Development of PWPL since 2005. Prior thereto, Vice  President, Engineering of PWPL since 2004. Prior thereto, Manager,  Exploitation of PWPL.                                                                                                                                                                                                                                                                                                     |
|                                               |       |                                                              |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 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. Prior thereto,  partner in Calgary based law firm.                       |

 

28

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| **Name, Province/State and  Country of Residence** | ** ** | **Positions and Offices Held**                        | ** ** | **Principal Occupations  during the Five Preceding Years**                                                                                                                                                                                                                                                                                        |
|----------------------------------------------------|------------|-------------------------------------------------------|------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| ** **                                         | ** ** | ** **                                            | ** ** | ** **                                                                                                                                                                                                                                                                                                                                        |
| Eric J. Obreiter  Alberta, Canada                  |       | Senior Vice President,  Production                    |       | Senior Vice President,  Production of PWPL since January 11, 2008. Prior thereto, Vice President,  Production of PWPL since 2005. Prior thereto, Manager, Production Central of  PWPL.                                                                                                                                                            |
|                                               |       |                                                  |       |                                                                                                                                                                                                                                                                                                                                              |
| John Artym  Alberta, Canada                        |       | Vice President, Health, Safety  and Training          |       | Vice President, Health, Safety  and Training of PWPL since January 11, 2008. Prior thereto, Manager, Health,  Safety and Training of PWPL since 2004. Prior thereto, various health and  safety management positions held with PWPL, BJ Services Company and its  predecessor Nowsco Well Service Ltd. (a private oil and gas services  company). |
|                                               |       |                                                  |       |                                                                                                                                                                                                                                                                                                                                              |
| Brett Frostad  Alberta, Canada                     |       | Vice President, Exploration;  Heavy Oil District      |       | Vice President, Exploration;  Heavy Oil District of PWPL since January 11, 2008. Prior thereto, Vice  President, Exploration North of PWPL since 2007. Prior thereto, Team Manager,  Swan Hills of PWPL since 2005. Prior thereto, District Geologist of PWPL  since 2004. Prior thereto, Senior Geologist of PWPL since 2002.                    |
|                                               |       |                                                  |       |                                                                                                                                                                                                                                                                                                                                              |
| Gregg Gegunde  Alberta, Canada                     |       | Vice President, Development;  Heavy Oil District      |       | Vice President, Development;  Heavy Oil District of PWPL since January 11, 2008. Prior thereto, Vice  President, Development North of PWPL since June 2005. Prior thereto, Manager,  Production Plains of PWPL.                                                                                                                                   |
|                                               |       |                                                  |       |                                                                                                                                                                                                                                                                                                                                              |
| Brian Keller  Alberta, Canada                      |       | Vice President, Exploration;  Light Oil District      |       | Vice President, Exploration;  Light Oil District of PWPL since January 11, 2008. Prior thereto, Vice  President of Exploitation of Canetic since November 2006. Prior thereto,  Director of Geology and Geophysics of Acclaim.                                                                                                                    |
|                                               |       |                                                  |       |                                                                                                                                                                                                                                                                                                                                              |
| Lucas Law  Alberta, Canada                         |       | Vice President, Acquisitions  and Divestments         |       | Vice President, Acquisitions  and Divestments of PWPL since January 11, 2008. Prior thereto, Vice  President, Asset Management of PWPL since 2006. Prior thereto, Manager,  Corporate Development since 2005. Prior thereto, Supervisor, Exploitation  since 2004. Prior thereto, Team Leader, Petrovera Resources.                               |
|                                               |       |                                                  |       |                                                                                                                                                                                                                                                                                                                                              |
| Doug Marjerrison  Alberta, Canada                  |       | Vice President, Development;  Gas District            |       | Vice President, Development;  Gas District of PWPL since January 11, 2008. Prior thereto, Manager, Border  Plains/Southern Business Unit of Canetic since July 2007. Prior thereto,  Manager, Southern Business Unit of Canetic since September 2006. Prior  thereto, Exploitation Engineer with Canetic.                                         |
|                                               |       |                                                  |       |                                                                                                                                                                                                                                                                                                                                              |
| Bill Morgan  Alberta, Canada                       |       | Vice President, Joint Venture  and Midstream Services |       | Vice President, Joint Venture  and Midstream Services of PWPL since January 11, 2008. Prior thereto,  Manager, Operations Plains/South of PWPL since 2006. Prior thereto, Manager,  Joint Venture of PWPL.                                                                                                                                        |

 

29

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| **Name, Province/State and  Country of Residence** | ** ** | **Positions and Offices Held**                                | ** ** | **Principal Occupations  during the Five Preceding Years**                                                                                                                                                                                                                                                                                                                                                                                                                                                                                |
|----------------------------------------------------|------------|---------------------------------------------------------------|------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| ** **                                         | ** ** | ** **                                                    | ** ** | ** **                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                |
| Keith Rockley  Alberta, Canada                     |       | Vice President, Human  Resources and Corporate Administration |       | Vice President, Human  Resources and Corporate Administration of PWPL since January 11, 2008. Prior  thereto, Vice President, Human Resources and Corporate Administration of  Canetic since January 2006. Prior thereto, Vice-President Human Resources and  Corporate Administration of Acclaim since November 2005. Prior thereto,  President of Human Resource Solutions Inc. (a private consulting business)  from April 2005 to October 2005. Prior thereto, Manager, Human Resources,  Husky Energy Inc. (an oil and gas company). |
|                                               |       |                                                          |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| Don Robson  Alberta, Canada                        |       | Vice President, Land                                          |       | Vice President, Land of PWPL  since January 11, 2008. Prior thereto, Vice President, Land of Canetic since  2006. Prior thereto, Vice President, Land of Acclaim since 2005. Prior  thereto, Manager Land Negotiations and Director of Land of Acclaim since  2004. Prior thereto, Land Manager at Energy North Inc. (an oil and gas  company).                                                                                                                                                                                           |
|                                               |       |                                                          |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| Dave Sterna  Alberta, Canada                       |       | Vice President, Marketing                                     |       | Vice President, Marketing of  PWPL since January 11, 2008. Prior thereto, Vice President, Corporate  Planning and Marketing of Canetic since January 2006. Prior thereto, Vice  President, Corporate Planning and Marketing of Acclaim since November 2005.  Prior thereto, Director of Marketing for Acclaim since September 2004. Prior  thereto, Director of Marketing for Calpine Canada (an energy company).                                                                                                                         |
|                                               |       |                                                          |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| Kristian Tange  Alberta, Canada                    |       | Vice President, Corporate  Development and Planning           |       | Vice President, Corporate  Development and Planning of PWPL since January 11, 2008. Prior thereto, Vice  President, Business Development of PWPL since 2005. Prior thereto, Manager,  Marketing of PWPL since 2003. Prior thereto, Manager, Natural Gas Marketing  of PWPL.                                                                                                                                                                                                                                                               |
|                                               |       |                                                          |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| Anne Thomson  Alberta, Canada                      |       | Vice President, Exploration;  Gas District                    |       | Vice President, Exploration;  Gas District of PWPL since January 11, 2008. Prior thereto, Vice President,  Exploration South of PWPL since June 2005. Prior thereto, Manager,  Exploration of PWPL since 2003. Prior thereto, District Geologist of PWPL.                                                                                                                                                                                                                                                                                 |

 

30

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| **Name, Province/State and  Country of Residence** | ** ** | **Positions and Offices Held**                   | ** ** | **Principal Occupations  during the Five Preceding Years**                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
|----------------------------------------------------|------------|--------------------------------------------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| ** **                                         | ** ** | ** **                                       | ** ** | ** **                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| Donald Wood  Alberta, Canada                       |       | Vice President, Development;  Light Oil District |       | Vice President, Development;  Light Oil District of PWPL since January 11, 2008. Prior thereto, Vice  President, Development South of PWPL since September 2007. Prior thereto,  President and Chief Executive Officer of C1 Energy Ltd. (a public oil and gas  company) since January 2007. Prior thereto, Executive Vice President and  Chief Operating Officer of C1 Energy Ltd. since June 2006. Prior thereto,  President and Chief Executive Officer of High Energy Resources Limited (a  private oil and gas company) since February 2005. Prior thereto, President  and Chief Executive Officer of Kensington Energy Ltd. (a public oil and gas  company). |
|                                               |       |                                             |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |
| Sherry Wendt  Alberta, Canada                      |       | Corporate Secretary                              |       | Corporate Secretary of PWPL  since February 8, 2008. Prior thereto, Corporate Counsel at PWPL since  2007. Prior thereto, practiced with the law firm Bennett Jones LLP.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |

 

----

Notes:

(1)          Member of theaudit committee.

(2)          Member of thehuman resources and compensation committee.

(3)          Member of thereserves committee.

(4)          Member of thegovernance committee.

(5)          Member of thehealth, safety and environment committee.

 

As at March 26, 2008, thedirectors and executive officers of PWPL, as a group, beneficially owned, orcontrolled or directed, directly or indirectly, 1,345,893 Trust Units orapproximately 0.4 percent of the issued and outstanding Trust Units.

 

**Cease Trade Orders, Bankruptcies, Penalties orSanctions**

** **

Except as otherwise disclosedherein,****no director or executiveofficer of PWPL (nor any personal holding company of any of such persons) is,as of the date of this Annual Information Form, or was within ten years beforethe date of this Annual Information Form, a director, Chief Executive Officeror Chief Financial Officer of any company (including PWPL), that:

 

(a)                                  was subject to a cease trade order (including amanagement cease trade order), an order similar to a cease trade order or anorder that denied the relevant company access to any exemption under securitieslegislation, in each case that was in effect for a period of more than 30 consecutivedays (collectively, an “**Order**”)that was issued while the director or executive officer was acting in thecapacity as director, Chief Executive Officer or Chief Financial Officer; or

 

(b)                                 was subject to an Order that was issued afterthe director or executive officer ceased to be a director, Chief ExecutiveOfficer or Chief Financial Officer and which resulted from an event thatoccurred while that person was acting in the capacity as director, ChiefExecutive Officer or Chief Financial Officer.

 

Daryl Gilbert is a director ofGlobel Direct, Inc., which was subject to a cease trade order issued by theBritish Columbia Securities Commission on November 20, 2002 and the AlbertaSecurities Commission on November 22, 2002 for delay in filing financialstatements. The required financial statements were filed and the cease tradeorders were revoked effective December 23, 2002. The company sought andreceived protection under CCAA in June 2007, and after a failed restructuringeffort, a receiver was appointed by one of the company’s lenders in December2007.

 

31

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Except as otherwise disclosedherein, no director or executive officer of PWPL (nor any personal holdingcompany of any of such persons), or shareholder holding a sufficient number ofsecurities of Penn West to affect materially the control of Penn West:

 

(a)                                  is, as of the date of this Annual InformationForm, or has been within the ten years before the date of this AnnualInformation Form, a director or executive officer of any company (includingPWPL) that, while that person was acting in that capacity, or within a year ofthat person ceasing to act in that capacity, became bankrupt, made a proposalunder any legislation relating to bankruptcy or insolvency or was subject to orinstituted any proceedings, arrangement or compromise with creditors or had areceiver, receiver manager or trustee appointed to hold its assets; or

 

(b)                                 has, within the ten years before the date ofthis Annual Information Form, become bankrupt, made a proposal under anylegislation relating to bankruptcy or insolvency, or become subject to orinstituted any proceedings, arrangement or compromise with creditors, or had areceiver, receiver manager or trustee appointed to hold the assets of thedirector, executive officer or shareholder.

 

John A. Brussa was a director ofImperial Metals 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. The reorganization resulted in the creation of twopublic corporations, Imperial Metals Corporation and IEI Energy Inc.(subsequently renamed Rider Resources Ltd.), both of which were listed on theTSX.

 

James C. Smith was, from May1999 to March 2000, Vice President and Chief Financial Officer of ProbeExploration Inc., an oil and gas company listed on the TSX. Mr. Smith joinedProbe Exploration Inc. in order to assist management and the Board of Directorsof the company in their efforts to restructure the company’s finances or sellassets to improve its financial situation. Such efforts did not succeed and thecompany’s lender appointed a receiver in March 2000.

 

No director or executive officerof PWPL (nor any personal holding company of any of such persons), orshareholder holding a sufficient number of securities of Penn West to affectmaterially the control of Penn West, has been subject to:

 

(a)                                  any penalties or sanctions imposed by a courtrelating to securities legislation or by a securities regulatory authority orhas entered into a settlement agreement with a securities regulatory authority;or

 

(b)                                 any other penalties or sanctions imposed by acourt or regulatory body that would likely be considered important to areasonable investor in making an investment decision.

 

**Conflicts of Interest**

** **

The Board of Directors hasadopted a Code of Business Conduct and Ethics and a Code of Ethics for Officersand Senior Financial Management (the “**Codes**”).In general, the private investment activities of employees, directors andofficers are not prohibited, however, should an existing investment pose apotential conflict of interest the potential conflict is required by the Codesto be disclosed to the Chief Executive Officer or the Board of Directors. Anyother activities posing a potential conflict of interest are also required bythe Codes to be disclosed to the Chief Executive Officer or the Board ofDirectors. Any such potential conflicts of interests will be dealt with openlywith full disclosure of the nature and extent of the potential conflicts ofinterests with Penn West.

 

It is acknowledged in the Codesthat the directors may be directors or officers of other entities engaged inthe oil and gas business, and that such entities may compete directly orindirectly with Penn West. Passive investments in public or private entities ofless than one per cent of the outstanding shares will not be viewed as “competing”with Penn West. No executive officer or employee of PWPL should be a directoror officer of any entity engaged in the oil and gas business unless expresslyauthorized by the Board of Directors. Any director of PWPL who is activelyengaged in the management of, or who owns an investment of one per cent or moreof the outstanding shares, in public or private entities shall disclose suchholding 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 toresolve such matters with a view to the best interests of Penn West. Suchactions, without limitation, may include excluding such directors, officers oremployees from certain information or activities of Penn West.

 

The ABCA provides that in theevent that an officer or director is a party to, or is a director or an officerof or has a material interest in any person who is a party to, a materialcontract or material transaction or proposed material contract or proposedmaterial transaction, such officer or director shall disclose the nature andextent of his or her interest and shall refrain from voting to approve suchcontract or transaction. See “Risk Factors – Potential Conflicts of Interest”.

 

As of the date hereof, Penn Westis not aware of any existing or potential material conflicts of interestbetween Penn West or a Subsidiary of Penn West and any director or officer ofPenn West or of any Subsidiary of Penn West, including PWPL.

 

**Promoters**

** **

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

 

**AUDIT COMMITTEE DISCLOSURES**

** **

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

 

**Composition of the Audit Committee and RelevantEducation and Experience**

** **

The members of the AuditCommittee are James C. Smith, chairman, and James E. Allard, Shirley A.McClellan and Frank Potter, each of whom is independent and financiallyliterate within the meaning of NI 52-110. The following comprises a briefsummary of each member’s education and experience that is relevant to theperformance of his responsibilities as an Audit Committee member.

 

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

*** ***

Mr. Smith is a CharteredAccountant with over 35 years of experience in public accounting and industry. Since1998, he has been a business consultant to a number of public and privatecompanies operating in the oil and gas industry. From 2002 until its sale in2006, he was also the Chief Financial Officer of Mercury Energy Corporation, aprivate oil and natural gas company, and from 2001 until the sale of thecompany in 2003, was the Chief Financial Officer of Segue Energy Corporation, aprivate oil and natural gas company. From 1999 to 2000, Mr. Smith was the VicePresident and Chief Financial Officer of Probe Exploration Inc., a publiclytraded oil and natural gas company. While Mr. Smith was the Vice President andChief Financial Officer of Crestar Energy Inc. from its inception in 1992 until1998, the company completed an initial public offering, was listed on the TSXand completed several major debt and equity financing transactions. Mr. Smith iscurrently a director of TG World Equity Corp., Pure Energy Services Inc. andGrey Wolf Exploration Inc.

 

***JamesE. Allard***

*** ***

Mr. Allard received his Bachelorof Science degree in Business Administration from the University of Connecticutand completed the Advanced Management Program at Harvard University. Mr. Allardhas focused his career on international finance in the petroleum industry forthe past 40 years serving as CEO, CFO and a director of a number of publiclytraded and private companies. During the past eight years he served on theboard of the Alberta Securities Commission, acting as the sole external trusteeand advisor to a mid-sized pension plan and serves as a director and advisor toseveral companies. From 1981 to 1995, he served as a senior executive officerof Amoco Corporation as well as a director of Amoco Canada, then Canada’slargest natural gas producer.

 

***FrankPotter***

*** ***

Mr. Potter attended Royal Military College of Science, and is a Fellowof the Institute of Canadian Bankers. Mr. Potter has been the Chairman since1995 of Emerging Markets Advisors, Inc., a Toronto-based consultancy thatassists corporations in

 

33

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making and managing direct investments internationally. Prior thereto,Mr. Potter was executive director of The World Bank Group in Washington, andwas subsequently senior advisor at the federal Department of Finance. Mr.Potter is a director of a number of public and private corporations and publicservice organizations.

 

***ShirleyA. McClellan***

*** ***

Mrs. McClellan brings to Penn West the experience gained over 20 yearsof distinguished service to the Province of Alberta. Her career historyincludes the offices of Deputy Premier of Alberta from 2001 to 2007, Ministerof Finance of Alberta from 2004 to 2007 and Chair of the Treasury Board andVice-Chair of the Agenda and Priorities Committee of the Alberta Assembly. Mrs.McClellan has served a total of six terms as a Member of the AlbertaLegislative Assembly representing the constituency of Drumheller-Stettler. Overthis time period, she has held numerous other portfolios, including Minister ofAgriculture, Food and Rural Development, Minister of International andIntergovernmental Relations, Minister of Community Development, and Minister ofHealth. Mrs. McClellan actively serves her community and is particularlypassionate about enhancing further education in rural areas. She is a formerdirector of the Alberta Association of Continuing Education and the CanadianAssociation for Continuing Education.

 

**Pre-Approval Policies and Procedures for Non-AuditServices**

** **

The terms of the engagement ofPenn West’s external auditors to provide audit services, including the budgetedfees for such audit services and the representations and disclaimer relatingthereto, must be pre-approved by the entire Audit Committee.

 

With respect to any engagementsof Penn West’s external auditors for non-audit services, Penn West must obtainthe approval of the Audit Committee or the Chairman of the Audit Committee priorto retaining the external auditors to complete such engagement. If suchpre-approval is provided by the Chairman of the Audit Committee, the Chairmanshall report to the Audit Committee on any non-audit service engagementpre-approved by him at the Audit Committee’s first scheduled meeting followingsuch pre-approval.

 

If, after using its reasonablebest efforts, Penn West is unable to contact the Chairman of the AuditCommittee on a timely basis to obtain the pre-approval contemplated by thepreceding paragraph, Penn West may obtain the required pre-approval from anyother member of the Audit Committee, provided that any such Audit Committeemember shall report to the Audit Committee on any non-audit service engagementpre-approved by him at the Audit Committee’s first scheduled meeting followingsuch pre-approval.

 

**External Auditor Service Fees**

** **

The following is a summary ofthe fees paid to KPMG LLP for external audit and other services.

 

***AuditFees***

*** ***

The aggregate fees billed by ourexternal auditor in each of the last two fiscal years for audit services,including Sarbanes – Oxley compliance related services, were:

 
| 2007   |   | -      |   | $      | 1,045,000 |   |
|--------|--------|--------|--------|--------|-----------|--------|
|   |   |   |   |   |      |   |
| 2006   |   | -      |   | $      | 610,000   |   |

 

***AuditRelated Fees***

*** ***

The aggregate fees billed ineach of the last two fiscal years by our external auditor for assurance andrelated services that are reasonably related to the performance of the audit orreview of our financial statements (and not included in audit services feesabove) were:

 
| 2007   |   | -      |   | $      | 120,000 |   |
|--------|--------|--------|--------|--------|---------|--------|
|   |   |   |   |   |    |
| 2006   |   | -      |   | $      | 105,000 |   |

 

The services comprising the feesdisclosed under this category include French translation services.

 

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***TaxFees***

*** ***

The aggregate fees billed ineach of the last two fiscal years by our external auditor for professionalservices for tax compliance, tax advice and tax planning were:

 
| 2007   |   | -      |   | $      | 7,914  |   |
|--------|--------|--------|--------|--------|--------|--------|
|   |   |   |   |   |   |
| 2006   |   | -      |   | $      | 18,341 |   |

 

The services comprising the feesdisclosed under this category include the following:  assistance and advice in relation to thecommunication of the taxability of distributions to Unitholders and the reviewof corporate income tax returns.

 

***AllOther Fees***

*** ***

The aggregate fees billed ineach of the last two fiscal years by our external auditor for products andservices not included under the headings Audit Fees, Audit Related Fees and TaxFees were:

 
| 2007   |   | -      |   | $      | NIL    |   |
|--------|--------|--------|--------|--------|--------|--------|
|   |   |   |   |   |   |
| 2006   |   | -      |   | $      | NIL    |   |

 

**Reliance on Exemptions**

** **

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

 

**Audit Committee Oversight**

** **

At no time since thecommencement of Penn West’s most recently completed financial year has arecommendation of the Audit Committee to nominate or compensate an externalauditor not been adopted by the Board of Directors of PWPL.

 

**DISTRIBUTIONS TO UNITHOLDERS**

** **

Since our formation as a trust,monthly cash distributions have been declared in the following amounts, eachamount being paid in the following month:

 
| **For the Month** | ** ** | **Distributions per Unit** | ** ** |
|-------------------|------------|----------------------------|------------|
| **Ended**         | ** ** | **2008**                   | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
| January           |       | $                          | 0.34       |   | $ | 0.34 |   | $ | 0.31 |   | N/A |   |
| February          |       | 0.34                       |       | 0.34 |   | 0.34 |   | N/A |   |
| March             |       | 0.34                       |       | 0.34 |   | 0.34 |   | N/A |   |
| April             |       | —                     |       | 0.34 |   | 0.34 |   | N/A |   |
| May               |       | —                     |       | 0.34 |   | 0.34 |   | N/A |   |
| June              |       | —                     |       | 0.34 |   | 0.34 |   | $ | 0.26 |   |
| July              |       | —                     |       | 0.34 |   | 0.34 |   | 0.26 |   |
| August            |       | —                     |       | 0.34 |   | 0.34 |   | 0.26 |   |
| September         |       | —                     |       | 0.34 |   | 0.34 |   | 0.26 |   |
| October           |       | —                     |       | 0.34 |   | 0.34 |   | 0.31 |   |
| November          |       | —                     |       | 0.34 |   | 0.34 |   | 0.31 |   |
| December          |       | —                     |       | 0.34 |   | 0.34 |   | 0.31 |   |
| Total             |       | $                          | 1.02       |   | $ | 4.08 |   | $ | 4.05 |   | $ | 1.97 |   |

 

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For Canadian and United Statesincome tax purposes, cash distributions paid to Unitholders in 2005, 2006 and2007 were 100 percent taxable as other income.

 

**MARKET FOR SECURITIES**

** **

The Trust Units are listed andtraded on the TSX under the symbol PWT.UN and on the NYSE under the symbol PWE.The following tables set forth certain trading information for our Trust Unitsin 2007.

 
| ** ** | ** ** | **TSX**                            | ** ** |
|------------|------------|------------------------------------|------------|
| **Period** | ** ** | **Unit price ($)  High** | ** ** | **Unit price ($)  Low** | ** ** | **Volume** | ** ** |
| ** ** | ** ** | ** **                         | ** ** | ** ** | ** ** | ** ** | ** ** |
| January    |       | 35.80                              |       | 32.32 |   | 17,597,965 |   |
| February   |       | 36.88                              |       | 34.09 |   | 11,851,438 |   |
| March      |       | 36.05                              |       | 32.48 |   | 14,490,763 |   |
| April      |       | 34.63                              |       | 33.11 |   | 11,900,009 |   |
| May        |       | 38.33                              |       | 33.12 |   | 15,145,415 |   |
| June       |       | 38.15                              |       | 33.50 |   | 15,215,785 |   |
| July       |       | 36.09                              |       | 32.57 |   | 11,523,717 |   |
| August     |       | 33.48                              |       | 28.48 |   | 14,511,853 |   |
| September  |       | 31.46                              |       | 28.66 |   | 12,486,728 |   |
| October    |       | 31.83                              |       | 29.89 |   | 15,984,431 |   |
| November   |       | 30.27                              |       | 25.90 |   | 20,602,889 |   |
| December   |       | 27.31                              |       | 25.25 |   | 19,265,161 |   |

 
| ** ** | ** ** | **NYSE**                                   | ** ** |
|------------|------------|--------------------------------------------|------------|
| **Period** | ** ** | **Unit price ($ US)  High** | ** ** | **Unit price ($ US)  Low** | ** ** | **Volume** | ** ** |
| ** ** | ** ** | ** **                                 | ** ** | ** ** | ** ** | ** ** | ** ** |
| January    |       | 30.50                                      |       | 27.50 |   | 18,695,800 |   |
| February   |       | 31.81                                      |       | 29.08 |   | 13,746,969 |   |
| March      |       | 31.11                                      |       | 27.61 |   | 18,183,252 |   |
| April      |       | 30.58                                      |       | 29.18 |   | 11,484,019 |   |
| May        |       | 36.30                                      |       | 29.93 |   | 20,095,788 |   |
| June       |       | 36.05                                      |       | 31.25 |   | 14,163,452 |   |
| July       |       | 34.58                                      |       | 30.71 |   | 14,011,508 |   |
| August     |       | 31.50                                      |       | 26.47 |   | 20,417,456 |   |
| September  |       | 31.42                                      |       | 28.42 |   | 15,805,123 |   |
| October    |       | 33.06                                      |       | 30.57 |   | 17,971,612 |   |
| November   |       | 32.17                                      |       | 26.06 |   | 28,651,264 |   |
| December   |       | 27.10                                      |       | 25.61 |   | 27,558,864 |   |

 

Penn West assumed the 7.2%Debentures and the 8% 2005 Debentures from Vault on January 10, 2008 inconnection with the Vault Acquisition. The 7.2% Debentures and the 8% 2005Debentures began trading on the TSX as securities of Penn West onJanuary 15, 2008 under the symbols “PWT.DB.E” and “PWT.DB.C”,respectively.

 

Penn West assumed the 6.5% 2005Debentures, the 6.5% 2006 Debentures, the 8% 2004 Debentures and the 9.4%Debentures from Canetic on January 11, 2008 in connection with thecompletion of the Canetic Acquisition. The 6.5% 2005 Debentures, the 6.5% 2006Debentures, the 8% 2004 Debentures and the 9.4% Debentures began trading on theTSX as securities of Penn West on January 16, 2008 under the symbols “PWT.DB.D”,“PWT.DB.F”, “PWT.DB.B” and “PWT.DB.A”, respectively.

 

Penn West does not have anyclasses of securities that are outstanding but that are not listed or quoted ona market place. In addition, to Penn West’s knowledge, no securities of PennWest are held in escrow, are subject to a pooling agreement, or are subject toa contractual restriction on transfer (except in respect of pledges made tolenders).

 

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**INDUSTRY CONDITIONS**

** **

The oil and natural gas industryis subject to extensive controls and regulations governing its operations(including land tenure, exploration, development, production, refining,transportation, and marketing) imposed by legislation enacted by various levelsof government and with respect to pricing and taxation of oil and natural gasby agreements among the governments of Canada, Alberta, British Columbia andSaskatchewan, all of which should be carefully considered by investors in theoil and gas industry. It is not expected that any of these controls orregulations will affect our operations in a manner materially different thanthey would affect other oil and gas companies of similar size. All currentlegislation is a matter of public record and we are unable to predict whatadditional legislation or amendments may be enacted. Outlined below are some ofthe principal aspects of legislation, regulations and agreements governing theoil and gas industry.

 

**Pricing and Marketing - Oil and Natural Gas**

** **

The producers of oil areentitled to negotiate sales contracts directly with oil purchasers, with theresult that the market determines the price of oil. Oil prices are primarilybased on worldwide supply and demand. The specific price depends in part on oilquality, prices of competing fuels, distance to market, the value of refinedproducts, the supply/demand balance, geo-political events and other contractualterms. Oil exporters are also entitled to enter into export contracts withterms not exceeding one year in the case of light crude oil and two years inthe case of heavy crude oil, provided that an order approving such export hasbeen obtained from the National Energy Board of Canada (the “**NEB**”). Any oil export to be made pursuantto a contract of longer duration (to a maximum of 25 years) requires anexporter to obtain an export licence from the NEB and the issuance of suchlicence requires the approval of the Governor in Council.

 

The price of natural gas isdetermined by negotiation between buyers and sellers. Natural gas exported fromCanada is subject to regulation by the NEB and the Government of Canada.Exporters are free to negotiate prices and other terms with purchasers,provided that the export contracts must continue to meet certain other criteriaprescribed by the NEB and the Government of Canada. Natural gas (other than itsconstituent by-products of propane, butane and ethane) exports for a term ofless than two years or for a term of two years to 20 years (in quantities ofnot more than 30,000 m3/day), must be made pursuant to an NEB order.Any natural gas export to be made pursuant to a contract of longer duration (toa maximum of 25 years) or a larger quantity requires an exporter to obtain anexport licence from the NEB and the issuance of such licence requires theapproval of the Governor in Council.

 

The governments of Alberta,British Columbia, and Saskatchewan also regulate the volume of natural gas thatmay be removed from those provinces for consumption elsewhere based on suchfactors as reserve availability, transportation arrangements, and marketconsiderations.

 

**Pipeline Capacity**

** **

Although pipeline expansions areongoing, insufficient firm pipeline capacity can from time to time impede ourability to produce and market our oil and natural gas production.

 

**The North American Free Trade Agreement**

** **

The North American Free TradeAgreement (“**NAFTA**”) among thegovernments of Canada, United States of America, and Mexico became effective onJanuary 1, 1994. NAFTA carries forward most of the material energy termsthat are contained in the Canada United States Free Trade Agreement. In thecontext of energy resources, Canada continues to remain free to determinewhether exports of energy resources to the United States or Mexico will beallowed, provided that any export restrictions do not: (i) reduce theproportion of energy resources exported relative to domestic use (based uponthe proportion prevailing in the most recent 36 month period); (ii) impose anexport 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 areprohibited from imposing minimum or maximum export or import pricerequirements, provided, in the case of export price requirements, prohibitionin any circumstances in which any other form of quantitative restriction isprohibited, and in the case of import-price requirements, such requirements donot apply with respect to enforcement of countervailing and anti-dumping ordersand undertakings.

 

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NAFTA contemplates the reductionof Mexican restrictive trade practices in the energy sector by 2010 andprohibits discriminatory border restrictions and export taxes. NAFTA alsocontemplates clearer disciplines on regulators to ensure fair implementation ofany regulatory changes and to minimize disruption of contractual arrangementsand avoid undue interference with pricing, marketing and distributionarrangements, which is important for Canadian natural gas exports.

 

**Provincial Royalties and Incentives**

** **

***General***

*** ***

In addition to federalregulation, each province has legislation and regulations that govern landtenure, royalties, production rates, environmental protection, and othermatters. The royalty regime is a significant factor in the profitability ofcrude oil, natural gas liquids, sulphur, and natural gas production. Royaltiespayable on production from lands other than Crown lands are determined bynegotiations between the mineral owner and the lessee, although production fromsuch lands is subject to certain provincial taxes and royalties. Crownroyalties are determined by governmental regulation and are generallycalculated as a percentage of the value of the gross production. The rate ofroyalties payable generally depends in part on prescribed reference prices,well productivity, geographical location, field discovery date, method ofrecovery, and the type or quality of the 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 areoften referred to as overriding royalties, gross overriding royalties, netprofits interests, or net carried interests.

 

Occasionally the governments ofthe western Canadian provinces create incentive programs for exploration anddevelopment. Such programs often provide for royalty rate reductions, royaltyholidays, and tax credits, and are generally introduced when commodity pricesare low. The programs are designed to encourage exploration and developmentactivity by improving earnings and funds flow within the industry. Royaltyholidays and reductions would reduce the amount of Crown royalties paid by oiland gas producers to the provincial governments and would increase the netincome and funds from operations of such producers. However, the trend inrecent years has been for provincial governments to eliminate, amend or allowsuch incentive programs to expire without renewal, and consequently few suchincentive programs are currently operative.

 

The Canadian federal corporateincome tax rate levied on taxable income is 22.1 percent effectiveJanuary 1, 2007 for active business income including resource income. Withthe elimination of the corporate surtax effective January 1, 2008 andother rate reductions introduced in the October 2007 Economic Statement andNotice of Ways and Means Motion and 2006 Federal Budget, the federalcorporate income tax rate will decrease to 15 percent in five steps: 19.5percent on January 1, 2008; 19 percent on January 1, 2009; 18 percenton January 1, 2010; 16.5 percent on January 1, 2011; and 15 percent onJanuary 1, 2012.

 

***Alberta***

*** ***

In Alberta, companies aregranted the right to explore, produce and develop petroleum and natural gasresources in exchange for royalties, bonus bid payments and rents. Currently,the amount of royalties that are payable is influenced by the oil production,density of the oil, and the vintage of the oil. Originally, the vintageclassified oil as “new oil” and “old oil” depending on when the oil pools werediscovered. If the pool was discovered prior to March 31, 1974 it isconsidered “old oil”, if it was discovered after March 31, 1974 and beforeSeptember 1, 1992, it is considered “new oil”. The Alberta governmentintroduced in 1992 a Third Tier Royalty with a base rate of 10 percent anda rate cap of 25 percent for oil pools discovered after September 1,1992. The new oil royalty reserved to the Crown has a base rate of10 percent and a rate cap of 30 percent. The old oil royalty reservedto the Crown has a base rate of 10 percent and a rate cap of35 percent.

 

The royalty reserved to theCrown in respect of natural gas production, subject to various incentives, isbetween 15 percent and 30 percent, in the case of new natural gas,and between 15 percent and 35 percent, in the case of old naturalgas, depending upon a prescribed or corporate average reference price. Naturalgas produced from qualifying intervals in eligible gas wells spudded ordeepened to a depth below 2,500 metres is also subject to a royalty exemption,the amount of which depends on the depth of the well.

 

Oil sands projects are subjectto a specific regulation made effective July 1, 1997, and expiringJune 30, 2009, which, among other things, determines the Crown’s share ofcrude and processed oil sands products.

 

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Regulations made pursuant to the*Mines and Minerals Act* (Alberta)provided various incentives for exploring and developing oil reserves inAlberta. However, the Alberta Government announced in August of 2006 that fourroyalty programs were to be amended and a new program was to be introduced. Inaddition, the Alberta Royalty Tax Credit Program (“**ARTC**”) was eliminated effective January 1, 2007. Theprograms affected by this announcement are: (i) Deep Gas Royalty Holiday;(ii) Low Productivity Well Royalty Reduction; (iii) Reactivated WellRoyalty Exemption; and (iv) Horizontal Re-Entry Royalty Reduction. The newprogram is the Innovative Energy Technologies Program (the “**IETP**”) which is intended to promote theproducers’ investment in research, technology and innovation for the purposesof improving environmental performance while creating commercial value. TheIETP provides royalty reductions that are presumed to reduce financial risk. AlbertaEnergy will be the one to decide which projects qualify and the level ofsupport that will be provided. The deadline for the IETP’s third round ofapplications was May 31, 2007. The successful applicants have not yet beenannounced and it appears, based on the previous two rounds, that the selectionprocess can take at least 8 months. The technical information gathered fromthis program is to be made public once a two-year confidentiality periodexpires.

 

On October 25, 2007, the Albertagovernment released a report entitled “The New Royalty Framework” containingthe government’s proposals for Alberta’s new royalty regime, which is scheduledto be effective on January 1, 2009. The proposal includes new royalty formulasfor conventional oil and natural gas that will operate on sliding scales thatare determined by commodity prices and well productivity. The proposal alsointroduces the policy of “shallow rights reversion”. The Alberta government isintending to implement this policy in order to maximize the development ofcurrently undeveloped resources, which is consistent with the government’sobjective of maximizing the recovery of known gas resources, while increasingroyalty revenues. The policy’s objective is for the mineral rights to shallowgas geological formations that are not being developed to revert back to thegovernment so that they may be made available for resale. It appears thatleaseholders will receive a grace period before the shallow zones revert to thegovernment, although the details of the policy have yet to be determined. Substantiallegislative, regulatory and systems updates will be introduced before changesbecome fully effective in January 2009. See “Risk Factors – New Alberta RoyaltyRegime”.

 

***BritishColumbia***

*** ***

Producers of oil and natural gasin the Province of 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 payableas a royalty in respect of oil depends on the type of oil, the value of theoil, the quantity of oil produced in a month, and the vintage of the oil.Generally, the vintage of oil is based on the determination of whether the oilis 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, whichtake into account the vintage of the oil, if the oil produced has already beensold and any royalty exempt value applicable (exempt wells). Oil produced fromnewly discovered pools may be exempt from the payment of a royalty for thefirst 36 months of production or 11,450 m(3) produced, whichever comesfirst; and the royalties for third-tier oil are the lowest reflecting thehigher costs of exploration and extraction that the producers would incur. Theroyalty payable on natural gas is determined by a sliding scale based on areference price, which is the greater of the price obtained by the producer,and a prescribed minimum price. However, when the reference price is below theselect price (a parameter used in the royalty rate formula), the royalty rateis fixed. As an incentive for the production and marketing of natural gas,which may have been flared, natural gas produced in association with oil has alower royalty than the royalty payable on non-conservation gas.

 

On May 30, 2003, the Ministry ofEnergy and Mines for the Province of British Columbia announced an Oil and GasDevelopment Strategy for the Heartlands (the “**Strategy**”).The Strategy is a comprehensive program to address road infrastructure,targeted royalties and regulatory reduction, and British Columbia servicesector opportunities. In addition, the Strategy will result in economic andemployment opportunities for communities in British Columbia’s heartlands.

 

Some of the financial incentivesin the Strategy include:

 

·                                          Royalty credits of up to $30 million annuallytowards the construction, upgrading, and maintenance of road infrastructure insupport of resource exploration and development. Funding will be contingentupon an equal contribution from industry.

 

39

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·                                          Changes to provincial royalties: new royaltyrates for low productivity natural gas to enhance marginally economic resourcesplays, royalty credits for deep gas exploration to locate new sources ofnatural gas, and royalty credits for summer drilling to expand the drillingseason.

 

***Saskatchewan***

*** ***

In Saskatchewan, the amountpayable as a royalty in respect of oil depends on the vintage of the oil, thetype of oil, the quantity of oil produced in a month, and the value of the oil.For Crown royalty and freehold production tax purposes, crude oil is considered“heavy oil”, “southwest designated oil”, or “non-heavy oil other than southwestdesignated oil”. The conventional royalty and production tax classifications (“fourth-tieroil” introduced October 1, 2002, “third-tier oil”, “new oil”, or “old oil”)of oil production are applicable to each of the three crude oil types. TheCrown royalty and freehold production tax structure for crude oil is pricesensitive and varies between the base royalty rates of 5 percent for all “fourth-tieroil” to 20 percent for “old oil”. Marginal royalty rates are30 percent for all “fourth-tier oil” to 45 percent for “old oil”.

 

The amount payable as a royaltyin respect of natural gas is determined by a sliding scale based on a referenceprice (which is the greater of the amount obtained by the producer and aprescribed minimum price), the quantity produced in a given month, the type ofnatural gas, and the vintage of the natural gas. As an incentive for theproduction and marketing of natural gas which may have been flared, the royaltyrate on natural gas produced in association with oil is less than onnon-associated natural gas. The royalty and production tax classifications ofgas production are “fourth-tier gas” introduced October 1, 2002, “third-tiergas”, “new gas”, and “old gas”. The Crown royalty and freehold production taxfor gas is price sensitive and varies between the base royalty rate of5 percent for “fourth-tier gas” and 20 percent for “old gas”. Themarginal royalty rates are between 30 percent for “fourth -tier gas” and45 percent for “old gas”.

 

On October 1, 2002, thefollowing changes were made to the royalty and tax regime in Saskatchewan:

 

·                  A new Crown royalty and freehold production taxregime applicable to associated natural gas (gas produced from oil wells) thatis gathered for use or sale. The royalty/tax is payable on associated naturalgas produced from an oil well that exceeds approximately 65 thousand cubicmetres in a month.

 

·                  A modified system of incentive volumes andmaximum royalty/tax rates applicable to the initial production from oil wellsand gas wells with a finished drilling date on or after October 1, 2002, wasintroduced. The incentive volumes are applicable to various well types and aresubject to a maximum royalty rate of 2.5 percent and a freehold productiontax rate of zero percent.

 

·                  The elimination of the re-entry and shortsection horizontal oil well royalty/tax categories. All horizontal oil wellswith a finished drilling date on or after October 1, 2002, will receive the “fourthtier” royalty/ tax rates and new incentive volumes.

 

In 1975, the Government ofSaskatchewan introduced a Royalty Tax Rebate (“**RTR**”) as a response to the federal government disallowingCrown royalties and similar taxes as a deductible business expense for incometax purposes. As of January 1, 2007, the remaining balance of any unused RTR islimited in its carry forward to five years since the federal government had theinitiative to reintroduce the full deduction of provincial resource royaltiesfrom federal and provincial taxable income.

 

On June 19, 2007, theGovernment of Saskatchewan introduced the Orphan Well and Facility LiabilityManagement Program pursuant to the amendment of the *Oil and Gas Conservation Act* and the *Oil and Gas Conservation Regulations*, 1985.The program includes a security deposit, which has two purposes: (i) preventingthe individual with insufficient financial capability from acquiring oil andgas wells or facilities; and (ii) in the case of a bankrupt company, the fundscover the decommissioning and reclaiming of orphan property. An additionalchange introduced is the mandatory licensing of all upstream oil and gasfacilities in Saskatchewan.

 

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**Land Tenure**

 

Crude oil and natural gaslocated in the western provinces is owned predominantly by the respectiveprovincial governments. Provincial governments grant rights to explore for andproduce oil and natural gas pursuant to leases, licences, and permits forvarying terms, the minimum of which is two years, and on conditions set forthin provincial legislation including requirements to perform specific work ormake payments. Oil and natural gas located in such provinces can also beprivately owned and rights to explore for and produce such oil and natural gasare granted by lease on such terms and conditions as may be negotiated.

 

**Environmental Regulation**

 

The oil and natural gas industryis subject to environmental regulations under a variety of provincial andfederal legislation. Environmental regulations impose, among other things,restrictions, prohibitions, liabilities and obligations in connection with thegeneration, handling, storage, transportation, treatment and disposal ofhazardous substances and waste and in connection with spills, releases andemissions of various substances to the environment, including substancesproduced in association with certain oil and gas industry operations.Environmental legislation also requires that wells, facility sites and otherproperties associated with our operations be operated, maintained, abandonedand reclaimed to the satisfaction of applicable regulatory authorities. Inaddition, certain types of operations, including exploration and developmentprojects and significant changes to certain existing projects, may require thesubmission and approval of environmental impact assessments or permitapplications. Compliance with this legislation can require significantexpenditures and a breach of such requirements could result in the suspensionor revocation of necessary licenses and authorizations, civil liability forpollution damage, and the imposition of material fines and penalties andfacility closures.

 

***Federal***

 

In December 2002, the Governmentof Canada ratified the Kyoto Protocol (“**Protocol**”).  The Protocol calls for Canada to reduce itsgreenhouse gas emissions to 6 percent below 1990 “business as usual” levelsbetween 2008 and 2012.  Given revisedestimates of Canada’s normal emissions levels, this target translates into anapproximate 40 percent gross reduction in Canada’s current emissions.  It is uncertain, based on the Updated ActionPlan announced by the federal government (see below), whether the Protocoltarget of 6 percent below 1990 emission levels will be enforced in Canada.  Bill C-288, which was intended to ensure thatCanada meets its global climate change obligations under the Protocol, waspassed by the House of Commons on February 14, 2007.  On April 26, 2007, the federal government releasedits Action Plan to Reduce Greenhouse Gases and Air Pollution (the “**Action Plan**”) also known as ecoACTION,which includes the regulatory framework for air emissions.  This Action Plan covers not only largeindustry, but regulates the fuel efficiency of vehicles and the strengtheningof energy standards for a number of energy using products.

 

The Government of Canada and theProvince of Alberta released on January 31, 2008 the final report of theCanada-Alberta ecoENERGY Carbon Capture and Storage Task Force, whichrecommends, among other things: (i) incorporating carbon capture and storageinto Canada’s clean air regulations; (ii) allocating new funding into projectsthrough competitive process; and (iii) targeting research to lower thecost of technology.

 

In order to strengthen theAction Plan, on March 10, 2008, the Government of Canada released “Turning theCorner – Taking Action to Fight Climate Change” (the “**Updated Action Plan**”) which provides someadditional guidance with respect to the federal government’s plan to reducegreenhouse gas emissions by 20 percent by 2020 and by 60 percent to 70 percentby 2050.

 

The Updated Action Plan isprimarily directed towards industrial emissions from certain specifiedindustries including oil sands, oil and gas and refining.  The Updated Action Plan is intended to createa carbon emissions trading market, including an offset system, to provideincentive to reduce greenhouse gas emissions and establish a market price for carbon.  There are mandatory reductions of 18 percentfrom the 2006 baseline starting in 2010 and an additional 2 percent per year insubsequent years for existing facilities. This target will be applied toregulated sectors on a facility-specific, sector-wide or corporate basis; inthe case of oils sands production, petroleum refining, natural gas pipelinesand upstream oil and gas, the target will be considered facility-specific(sectors in which the facilities are complex and diverse, or where emissionsare affected by factors beyond the control of the facility operator).  Emissions from new facilities, which arethose built between 2004 and 2011, will be based on a cleaner fuel standard toencourage continuous emissions intensity reductions over time, and will begranted a three-year grace period during which no emissions intensity targetswill apply.  Targets will begin to 

 

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apply on the fourth year ofcommercial operation and the baseline will be the third-year’s emissionsintensity, with a 2 percent continuous annual emission intensity improvementrequired.  The definition of new facilityalso includes greenfield facilities, major expansions constituting more than a25 percent increase in a facility’s physical capacity, as well as transformationsto a facility 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 beprocess-specific: oil sands plants built in 2012 and later, those which useheavier hydrocarbons, up-graders and in-situ production will have mandatorystandards in 2018 that will be based on carbon capture and storage.

 

In the following regulatedsectors, the Updated Action Plan will apply only to facilities exceeding aminimum annual emissions threshold: (i) 50,000 tonnes of CO2 equivalent peryear for natural gas pipelines; (ii) 3,000 tonnes of CO2 equivalent perupstream oil and gas facilities; and (iii) 10,000 boe/d per company.  These proposed thresholds are significantlystricter than the current Alberta regulatory threshold of 100,000 tonnes of CO2equivalent per year per facility.  See “IndustryConditions – Environmental Regulation – Alberta” below.

 

Four separate compliance mechanismsare provided in respect of the above targets: Technology Fund contributions;offset credits; clean development credits; and credits for early action.  The most significant of these compliancemechanisms, at least initially, will be the Technology Fund, to which regulatedentities will be able to contribute in order to comply with emissions intensityreductions.  The contribution rate willincrease over time, beginning at $15 per tonne for the 2010 to 2012 period,rising to $20 per tonne in 2013, and thereafter increasing at the nominal rateof gross domestic product growth. Contribution limits will correspondingly decline from 70 percent in 2010to nil in 2018.  Monies raised throughcontributions to the Technology Fund will be used to invest in technology toreduce greenhouse gas emissions. Alternatively, regulated entities may be able to receive credits forinvesting in large-scale and transformative projects at the same contributionrate and under similar requirements as mentioned above.

 

The offset system is intended toencourage emissions reductions from activities outside of the regulated sphere,allowing non-regulated entities to participate in and benefit from emissionsreduction activities.  In order togenerate offset credits, project proponents must propose and receive approvalfor emissions reduction activities that will be verified before offset creditswill be issued to the project proponent. Those credits can then be sold to regulated entities for use incompliance or non-regulated purchasers that wish to either cancel the offsetcredits or bank them for future use or sale.

 

Under the Updated Action Plan,regulated entities will also be able to purchase credits created through theClean Development Mechanism of the Protocol. The purchase of such emissions reduction credits will be restricted to10 percent of each firm’s regulatory obligation, with the added restrictionthat credits generated through forest sink projects will not be available foruse in complying with the Canadian regulations.

 

Finally, a one-time credit of upto 15 metric tons worth of emissions credits will be awarded to regulatedentities for emissions reduction activities undertaken between 1992 and2006.  These credits will be both tradableand bankable.

 

It is currently intended thatthe proposed greenhouse gas regulations will be published later in 2008, andthat the regulations will be finalized in 2009 prior to coming into force onJanuary 1, 2010.

 

***Alberta***

 

Environmental legislation in the Province ofAlberta has been consolidated into the *EnvironmentalProtection and Enhancement Act* (Alberta) (the “**EPEA**”), which came into force onSeptember 1, 1993, and the *Oil and GasConservation Act* (Alberta) (the “**OGCA**”).  The EPEA and OGCA impose stricterenvironmental standards, require more stringent compliance, reporting andmonitoring obligations, and significantly increased penalties.  In 2006, the Alberta Government enactedregulations pursuant to the EPEA to specifically target sulphur oxide andnitrous oxide emissions from industrial operations including the oil and gasindustry.  In addition, the reductionemission guidelines outlined in the *ClimateChange and Emissions Management Amendment Act*came into effect onJuly 1, 2007.  Under this legislation,Alberta facilities emitting more than 100,000 tonnes of greenhouse gases a yearmust reduce their emissions intensity by 12%. Industries have three options to choose from in order to meet thereduction requirements outlined in this legislation, and these are: (i) by makingimprovement to operations that result in reductions; (ii) by purchasingemission credits from other sectors or facilities that have emissions below the100,000 tonne threshold and are voluntarily reducing their emission; or (iii)by contributing to the Climate Change and Emissions Management Fund.  Industries can either choose one of theseoptions or a combination thereof.

 

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On January 24, 2008, the AlbertaGovernment announced a new climate change action plan that will cut Alberta’sprojected 400 million tonnes of emissions in half by 2050. This plan is basedon three areas: (i) carbon capture and storage, which will be mandatory for insitu oil sand facilities that use heavy fuels for steam generation; (ii) energyconservation and efficiency; and (iii) greening production through increasedinvestment in clean energy technology, including supporting research on new oilsands extraction processes, as well as the funding of projects that reduce thecost of separating CO2 from other emissions supporting carbon capture andstorage.

 

***BritishColumbia***

 

British Columbia’s *Environmental Assessment Act* became effective 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 theProvince’s strategy towards the environment and which includes targeting forzero net greenhouse gas emissions, promoting new investments in innovation, andbecoming the world’s leader in sustainable environmental management.  For this purpose, on December 18, 2007,proposals 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 and gasindustry, the objective is to achieve clean energy through conservation andenergy efficient practices, while competitiveness is advocated in order toattract investment for the development of the oil and gas sector. Among thechanges to be implemented are: (i) a new Net Profit Royalty Program; (ii) thecreation of a Petroleum Registry; (iii) the establishment of an infrastructureroyalty program (combining roads and pipelines); (iv) the elimination ofroutine flaring at producing wells; (v) the creation of policies and measuresfor the reduction of emissions; (vi) the development of unconventionalresources such as tight gas and coalbed gas; and (vii) the new Oil and GasTechnology Transfer Incentive Program that encourages the research, developmentand use of innovative technologies to increase recoveries from existingreserves and promotes responsible development of new oil and gas reserves.  In furtherance of these initiatives, onFebruary 19, 2008 the provincial government announced that starting on July 1,2008, provided the legislation is approved, a revenue-neutral carbon tax willbe applied to all fossil fuels used in the province. The tax would be phasedin, and the initial rate would be based on CO2 equivalent of $10 per tonne forthe first six months of 2009 and $15 per tonne for the last six months of 2009,followed by $5 per tonne increases on July of every year until 2012.  Tax credits and reductions will be used inorder to offset the tax revenues that the government would receive otherwise.

 

***PennWest and the Environment***

 

As the federal and provincial programsrelating to the regulation of the emission of greenhouse gases and other airpollutants are under development, we are currently unable to predict the totalimpact 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, we, in cooperation with the CanadianAssociation of Petroleum Producers, will continue to work with government todevelop an approach to deal with climate change issues that protects the industry’scompetitiveness, limits the cost and administrative burden of compliance and supportscontinued investment in the sector.  Inthe meantime, we will continue our current activities to reduce emissionsintensity, improve energy efficiency and develop CO2 injection andsequestration infrastructure.  See “RiskFactors – Environmental Regulation”.

 

We fully 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, CO2 sequestration and siteabandonment/reclamation.  Ourenvironmental programs are monitored to ensure that they comply with allgovernment environmental regulations and with our own environmental policies.The results of these programs are reviewed with our management and operationspersonnel.

 

Our Environmental Policy andEnvironmental Management Plan (“**EMP**”)encompass the 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.

 

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We maintain a program ofdetailed inspections, audits and field assessments to determine and quantifythe environmental 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 2008, 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 plan and test theinfrastructure required to inject and permanently “sequester” CO2 inhydrocarbon reservoirs.

 

During2007, we continued our pilot-scale CO2 injection program at Pembina, where theinjection of CO2 commenced in February 2005.  To date, in excess of 1.6 Bcf of liquid CO2 has beeninjected. If successful, the pilot could lead to a much larger enhanced oilrecovery program with potential to sequester very significant volumes of CO2. Also in 2007, we continued to participate instudies to develop a cost effective system to source large volumes of CO2 currently emitted within Alberta, and totransport it by pipeline for injection into producing oil fields in central Alberta.  See “Risk Factors – Resources Plays –Enhanced Oil Recovery”.

 

We are committed to meeting our responsibilities to protect theenvironment wherever we operate and we anticipate making increased expendituresof both a capital and an expense nature as a result of the increasinglystringent laws relating to the protection of the environment.  We will be taking such steps as required toensure continued compliance with applicable environmental legislation in each jurisdictionin which we operate.  We believe that weare currently in material compliance with applicable environmental laws andregulations.  We also believe that it isreasonably likely that the trend towards stricter standards in environmentallegislation and regulation will continue.

 

**RISK FACTORS**

 

The following is a summary ofcertain risk factors relating to the business of Penn West and the OperatingEntities.  The following information is asummary only of certain risk factors and is qualified in its entirety byreference to, and must be read in conjunction with, the detailed informationappearing elsewhere in this Annual Information Form.  Unitholders and potential Unitholders shouldconsider carefully the information contained herein and, in particular, thefollowing risk factors.

 

**Being a limitedpurpose trust makes us largely dependent upon the operations and assets of theOperating Entities.  If the oil andnatural gas reserves associated with the Operating Entities’ resourceproperties are not supplemented through additional development activities orthe acquisition of oil and natural gas properties, the ability of the OperatingEntities to continue to generate funds flow from operations for distribution toUnitholders may become adversely affected.**

 

We are entirely dependent uponthe operations and assets of the Operating Entities through our ownership,directly and indirectly, of securities of the Operating Entities, including thecommon shares 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 received fromthe 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.

 

**Volatility of Oil and Natural Gas Prices**

 

Our operational results and thefinancial condition of our Operating Entities and therefore the amounts paid tous and ultimately distributed to our Unitholders will be dependent on theprices received for oil and natural gas production. Oil and natural gas prices havefluctuated widely during recent years and are determined by economic, andin the case of oil prices, also political factors.  Supply and demand factors, including weatherand general economic conditions, as well as conditions in other oil and naturalgas regions, impact prices.  Any movementin oil and natural gas prices will have an effect on our funds flow fromoperations, financial condition and therefore on our financial position and thecash available to be distributed to our Unitholders.  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 if commodityprices 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.

 

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**Geo-Political Risks**

 

The marketability and price ofoil and natural gas that may be acquired or discovered by us is and willcontinue to be affected by political events throughout the world that causedisruptions in the supply of oil.  Conflicts,or conversely peaceful developments, arising in the Middle-East, and otherareas of the world, have a significant impact on the price of oil and naturalgas.  Any particular event could resultin a material decline in prices and therefore result in a reduction of theOperating Entities’ net production revenue and consequently the funds flowavailable for distribution to Unitholders.

 

In addition, our oil and naturalgas properties, wells and facilities could be subject to a terroristattack.  If any of our properties, wellsor facilities are the subject of a terrorist attack it could have a materialadverse effect on us.  We do not currentlyhave insurance to protect against the risk of terrorism.

 

**Depletion of Reserves**

 

Distributions of income from ourproperties, absent commodity price increases or cost effective exploration,acquisition and development activities, will decline over time in a mannerconsistent with declining production from typical oil, natural gas and naturalgas liquids reserves.  As we distribute aportion of our funds flow to Unitholders, we will not be reinvesting funds flowin the same manner as some other corporate industry participants and will onlyconduct limited exploratory activities as one of our main objectives is tomaximize long-term distributions. Accordingly, absent equity capital injections or increased debt levels,our production levels and reserves will decline over time and, absent changesto other factors, the level of income available for distributions will alsodecline over time.

 

Our future oil and natural gasreserves and production, and therefore our funds flows, will be highlydependent on our success in exploring and exploiting our reserve and land baseand acquiring additional reserves. Without reserve additions throughacquisition, exploration or development activities, our reserves and productionwill decline over time as our existing reserves are produced.

 

To the extent that externalsources of capital, including the issuance of additional Trust Units, become limitedor unavailable, our ability to make the necessary capital investments tomaintain or expand our oil and natural gas reserves will 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 thatwe will be successful in developing or acquiring additional reserves on termsthat meet our investment objectives.

 

**Variations in Foreign Exchange Rates and InterestRates**

 

World oil prices are quoted inUnited States dollars and the price received by Canadian producers is thereforeaffected by the Canadian/US dollar exchange rate which will fluctuate overtime.  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.  Such material increases in the value of theCanadian dollar have negatively impacted Penn West’s Operating Entitiesproduction revenues.  Any furthermaterial increases in the value of the Canadian dollar relative to the UnitedStates dollar would exacerbate this negative impact.  This increase in the exchange rate for theCanadian dollar and future Canadian/United States exchange rates couldaccordingly impact future distributions and the future value of our reserves asdetermined by independent evaluators.

 

To the extent that we engage inrisk management activities related to foreign exchange rates, there is creditrisk associated with counterparties with which we contract.

 

An increase in interest rates(whether as a result of a further deterioration of the credit market orotherwise) could result in a significant increase in the amount we pay toservice debt, resulting in a decrease in distributions to Unitholders, whichwould negatively impact the market price of the Trust Units.

 

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**Reserve and Resource Estimates**

 

There are numerous uncertaintiesinherent in estimating quantities of oil, natural gas and NGLs reserves andresources and funds flows to be derived therefrom, including many factorsbeyond our control.  The reserve andassociated funds flow information set forth in this Annual Information Form representsestimates only.  In general, estimates ofeconomically recoverable oil and natural gas reserves and resources and thefuture net funds flows therefrom are based upon a number of variable factorsand assumptions, such as historical production from the properties, productionrates, ultimate reserve recovery, timing and amount of capital expenditures,marketability of oil and natural gas, royalty rates, the assumed effects ofregulation by governmental agencies and future operating costs, all of whichmay vary from actual results.  All suchestimates are to some degree speculative, and classifications of reserves andresources are attempts to define the degree of speculation involved.  For those reasons, 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 reservesthat may be developed and produced in the future are sometimes based uponvolumetric calculations and upon analogy to similar types of reserves ratherthan actual production history. Estimates based on these methods are generally less reliable than thosebased on actual production history. Subsequent evaluation of the same reserves based upon production historyand production practices will result in variations in the estimated reservesand such variations could be material.

 

In accordance with applicablesecurities laws, GLJ and Sproule have used forecast price and cost estimates incalculating reserve quantities included in this Annual Information Form.  Actual future net funds flows will beaffected by other factors including but not limited to actual productionlevels, supply and demand for oil and natural gas, curtailments or increases inconsumption by oil and natural gas purchasers, changes in governmentalregulation or taxation and the impact of inflation on costs.

 

Actual production and fundsflows derived from reserves will vary from the reserve estimates contained inthe engineering reports summarized in this Annual Information Form, and suchvariations could be material.  Theengineering reports summarized in this Annual Information Form are based in parton the assumption that certain activities will be undertaken by us in futureyears and the further assumption that such activities will be successful.  The reserves and estimated funds flows to bederived therefrom contained in the engineering reports summarized in thisAnnual Information Form will be reduced, in future years, to the extent thatsuch activities are not undertaken or, if undertaken, do not achieve the levelof success assumed in the engineering reports summarized in this AnnualInformation Form.

 

**Environmental Regulation**

 

All phases of the oil andnatural gas business 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, management believes thepolitical climate appears to favour new programs for environmental laws andregulation, particularly in relation to the reduction of emissions, and thereis no assurance that any such programs, laws or regulations, if proposed andenacted, will not contain emission reduction targets which we cannot meet, andfinancial penalties or charges could be incurred as a result of the failure tomeet such targets.

 

In particular, there isuncertainty regarding the Kyoto Protocol and the Government of Canada’s Clean AirAct of 2006.  The Clean Air Act proposesto reduce greenhouse gas emissions and other contaminants, however emissiontargets and compliance deadlines differ from those outlined in the KyotoProtocol which was ratified by Canada. If passed, the Clean 

 

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Air Act may have adverseoperational and financial implications to us. Provincial emission reduction requirements, such as those contained inAlberta’s *Climate Change and EmissionsManagement Act*, may require the reduction of emissions or emissionsintensity of our operations and facilities. The direct or indirect costs of these regulations may adversely andmaterially affect our business.  Althoughwe believe that we are in material compliance with current applicableenvironmental regulations, no assurance can be given that environmental lawswill not result in a curtailment of production or a material increase in thecosts of production, development or exploration activities or otherwiseadversely affect our financial condition, results of operations orprospects.  Future changes in otherenvironmental legislation could occur and result in stricter standards andenforcement, 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 “IndustryConditions – Environmental Regulation”.

 

**Given theevolving nature of the debate related to climate change and the control ofgreenhouse gases and resulting requirements, it is not currently possible topredict either the nature of those requirements or the impact on us and ouroperations and financial condition.**

 

**Competition**

 

There is strong competitionrelating to all aspects of the oil and gas industry.  There are numerous trusts and conventionalexploration and production companies in the oil and gas industry, who are alsocompeting for the acquisition of properties with longer life reserves and propertieswith exploitation and development opportunities.  The SIFT Tax imposed by the Government ofCanada is expected by management to make our Trust Units less attractive asconsideration for acquisitions.  See “RiskFactors – Federal Tax Changes”.  As aresult of such increasing competition, it is expected to become more difficultto acquire producing assets and reserves on beneficial terms.  We also compete for skilled industrypersonnel with a substantial number of other oil and gas companies and trusts.

 

**Reliance on Management**

 

Unitholders will be dependent onthe management of PWPL in respect of the administration and management of allmatters relating to our operations. Investors who are not willing to rely on the management of PWPL shouldnot invest in the Trust Units or the Convertible Debentures.

 

**Federal Tax Changes**

 

On October 31, 2006, the Federal Minister ofFinance proposed to deny the deduction of distributions at the trust level andsubject any income of certain publicly traded mutual fund trusts to tax atrates comparable to the combined federal and provincial corporate tax and totreat such distributions as taxable dividends to the unitholders (the “**SIFT Tax**”). On December 21, 2006, the Federal Minister of Finance released draftlegislation to implement the SIFT Tax pursuant to which, commencing January 1,2011 (provided Penn West only experiences “normal growth” and no “undueexpansion” before then) certain distributions from us which would haveotherwise been taxed as ordinary income generally will be characterized asdividends to our Unitholders and will be subject to tax at the corporate ratesat the trust level.  On June 22, 2007,the legislation received Royal assent. The implementation of the SIFT Tax is expected to result in adverse taxconsequences to us and certain Unitholders (including most particularlyUnitholders that are tax deferred or Non-Residents of Canada) and may impactthe level of cash distributions from us.

 

Management of PWPL believes that the SIFT Taxhas reduced, and may further reduce, the value of the Trust Units, which wouldbe expected to increase the cost to Penn West of raising capital in the publiccapital markets.  In addition, managementof PWPL believes that the SIFT Tax: (a) has substantially eliminated anycompetitive advantage that Penn West and other Canadian energy trusts haveenjoyed relative to their corporate peers in raising capital in a tax-efficientmanner; and (b) may place Penn West and other Canadian energy trusts at acompetitive disadvantage relative to certain of their industry competitors,including US master limited partnerships, which will continue to not be subjectto entity level taxation.  The SIFT Taxmay also make the Trust Units less attractive as consideration for acquisitionsin the future.  As a result, it maybecome more difficult for us to compete effectively for acquisitionopportunities.

 

Further, the SIFT Tax provides that, whilethere is no intention to prevent “normal growth” during the transitionalperiod, any “undue expansion” would result in the transition period beingterminated with the loss of the benefit to us of that transitional 

 

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period. As a result, the adverse tax consequences resulting from the SIFT Taxcould be borne sooner than January 1, 2011.  On December 15, 2006, the Department ofFinance issued guidelines with respect to what is meant by “normal growth” inthis context.  Specifically, theDepartment of Finance stated that “normal growth” would include equity growthwithin certain “safe harbour” limits, measured by reference to a “specifiedinvestment flow-through’s” (“**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 outstandingpublicly-traded trust units, and not any convertible debt, options or otherinterests convertible into or exchangeable for trust units).  Those safe harbour limits are 40 percentfor the period from November 1, 2006 to December 31, 2007, and20 percent each for calendar year 2008, 2009 and 2010.  Moreover, these limits are cumulative, sothat any unused limit for a period carries over into the subsequentperiod.  Additional details of theDepartment of Finance’s guidelines include the following:

 

•              new equity for these purposes includes unitsand debt that is convertible into units (and may include other substitutes forequity if attempts are made to develop those);

 

•              replacing debt that was outstanding as ofOctober 31, 2006 with new equity, whether by a conversion into trust unitsof convertible debentures or otherwise, will not be considered growth for thesepurposes and will therefore not affect the safe harbour; and

 

•              the exchange, for trust units, of exchangeablepartnership units or exchangeable shares that were outstanding onOctober 31, 2006 will not be considered growth for those purposes and willtherefore not affect the safe harbour where the issuance of the trust units ismade in satisfaction of the exercise of the exchange right by a person otherthan the SIFT.

 

Penn West’s and Canetic’s combined marketcapitalization as of the close of trading on October 31, 2006, havingregard only to the issued and outstanding publicly-traded Trust Units andCanetic trust units at such date, was approximately $15 billion, which means thecombined “safe harbour” equity growth amount for the period endingDecember 31, 2007 is approximately $6 billion, and for each of calendaryear 2008, 2009 and 2010 is an additional approximately $3 billion (in anycase, not including equity, including convertible debentures, issued to replacedebt that was outstanding on October 31, 2006).

 

While these guidelines are such that it isunlikely they would affect our ability to raise the capital required tomaintain and grow our existing operations in the ordinary course during thetransition period, they may adversely affect the cost of raising capital andour ability to undertake more significant acquisitions.

 

Currently, the SIFT Tax rules provide that theSIFT Tax rate will be the federal general corporate income tax rate (which isanticipated to be 16.5 percent in 2011 and 15 percent in 2012) plus theprovincial SIFT tax factor discussed below.

 

On February 26, 2008, the Minister ofFinance announced (the “**Provincial SIFT TaxProposal**”) that instead of basing the provincial component of theSIFT Tax on a flat rate of 13 percent, the provincial component will be basedon the general provincial corporate income tax rate in each province in whichthe SIFT has a permanent establishment. For purposes of calculating this component of the tax, the generalcorporate taxable income allocation formula will be used.  Specifically, our taxable distributions willbe allocated to provinces by taking half of the aggregate of:

 

•      that proportion ofour taxable distributions for the year that our wages and salaries in theprovince are of our total wages and salaries in Canada; and

 

•      that proportion ofour taxable distributions for the year that our gross revenues in the provinceare of our total gross revenues in Canada.

 

Under the Provincial SIFT Tax Proposal we wouldbe considered to have a permanent establishment in Alberta only, where theprovincial tax rate in 2011 is expected to be 10 percent.  Taxable distributions that are not allocatedto any province would instead be subject to a 10 percent rate constituting theprovincial component.  There can be noassurance, however, that the Provincial SIFT Tax Proposal will be enacted asproposed.

 

**The long-termeffect of the SIFT Tax on us cannot be determined at this time, but may bematerially adverse to us and some or all of our Unitholders.**  Therecan be no assurance that we will be able to generate sufficient tax poolsand/or reorganize our legal and tax structure in order to mitigate, in whole orin part, the expected impact of the SIFT Tax.

 

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**Failure to Realize Anticipated Benefits ofAcquisitions and Dispositions**

 

We make acquisitions anddispositions of businesses and assets in the ordinary course of business.  Achieving the benefits of acquisitions(including, without limitation, the Vault Acquisition and the CaneticAcquisition) depends in part on successfully consolidating functions andintegrating operations and procedures in a timely and efficient manner, as wellas our ability to realize the anticipated growth opportunities and synergiesfrom combining 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 operationalmatters.  Management continually assessesthe value and contribution of services provided and assets required to providesuch services.  In this regard, non-coreassets are periodically disposed of, so that we can focus our efforts andresources more efficiently.  Depending onthe state of the market for such non-core assets, certain of our non-coreassets, if disposed of, could be expected to realize less than their carryingvalue in our financial statements.

 

**Incorrect Assessment of the Value of Acquisitions**

 

Acquisitions of oil and gasproperties or companies will be based in large part on engineering and economicassessments made by independent engineers. These assessments include a series of assumptions regarding such factorsas recoverability and marketability of oil and gas, future prices of oil andgas and operating costs, future capital expenditures and royalties and othergovernment levies which will be imposed over the producing life of thereserves.  Many of these factors aresubject to change and are beyond our control. All such assessments involve a measure of geological and engineeringuncertainty that could result in lower production and reserves thananticipated.

 

**Management of Growth**

 

We may be subject togrowth-related risks, including capacity constraints and pressure on ourinternal systems and controls.  Ourability to manage growth effectively will require us to continue to implementand improve our operational and financial systems and to expand, train andmanage our employee base.  Our inabilityto deal with this growth could have a material adverse impact on our business,operations and prospects.

 

**Changes in Legislation**

 

Income tax laws, or other lawsor government incentive programs relating to the oil and gas industry, such asthe treatment of mutual fund trusts and resource taxation, may in the future bechanged or interpreted in a manner that adversely affects us and ourUnitholders.  Tax authorities having jurisdictionover us or the Unitholders may disagree with how we calculate our income fortax purposes or could change administrative practises to our detriment or thedetriment of our Unitholders.

 

For such period of time as weoperate in a trust structure, we intend to continue to qualify as a mutual fundtrust for purposes of the Tax Act.  Wemay not, however, always be able to satisfy any future requirements for themaintenance of mutual fund trust status. Should our status as a mutual fund trust be lost or successfullychallenged by a relevant tax authority, certain adverse consequences may arisefor us and our Unitholders.  Some of thesignificant consequences of losing mutual fund trust status are as follows:

 

•      We would be taxed on certain types of income distributed to Unitholders,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 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 Canada wouldbecome taxable Canadian property.  TheseNon-Resident holders would be subject to Canadian income tax on any gainsrealized on a disposition of Trust Units held by them.

 

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•      Trust Units would not constitute qualified investments for registeredretirement savings plans (“**RRSPs**”),registered retirement income funds (“**RRIFs**”),registered education savings plans (“**RESPs**”)or deferred profit sharing plans.  If, atthe end of any month, one of these exempt plans holds Trust Units that are notqualified investments, the plan must pay a tax equal to one percent of the fairmarket value of the Trust Units at the time the Trust Units were acquired bythe exempt plan.  An RRSP or RRIF holdingnon-qualified Trust Units would be subject to taxation on income attributableto the Trust Units.  If an RESP holdsnon-qualified Trust Units, it may have its registration revoked by the Canada RevenueAgency.

 

In addition, we may take certainmeasures in the future to the extent we believe necessary to ensure that wemaintain our status as a mutual fund trust. These measures could be adverse to certain Unitholders, particularlyNon-Residents.  See “Risk Factors –Non-Resident Ownership of Trust Units”.

 

**New Alberta Royalty Regime**

 

On February 16, 2007, theAlberta government began a review of its royalty regime for oil sands,conventional oil and natural gas and coalbed methane with the stated intentionof assessing whether the existing royalty regime was providing Albertans with afair return on Alberta’s natural resources while maintaining an internationallycompetitive system that allows the Alberta economy to continue to prosper.

 

On October 25, 2007, the Albertagovernment released a report titled “The New Royalty Framework” (the “**Report**”) containing the government’sproposals for Alberta’s new royalty regime (the “**Proposed Royalty Regime**”), which is scheduled to take effecton January 1, 2009.  The Proposed RoyaltyRegime includes the following features:

 

•              New, simplified royalty formulas forconventional oil and natural gas that will operate on sliding scales that aredetermined by commodity prices and well productivity. The formulas eliminatethe need for conventional oil and natural gas tiers and several royaltyexemption programs.

 

•              A sliding scale will be implemented for oilsands royalty rates ranging from one to nine percent pre-payout and 25 to 40percent post-payout depending on the price of oil.

 

•              The province will exercise its existing rightto receive “royalty-in-kind” on oil sands projects (i.e. raw bitumen deliveredto the Crown-operated Alberta Petroleum Marketing Commission in lieu of cashroyalties).

 

•              The government will ensure that eligibleexpenditures and definitions of oil sands projects (also known as “ring fence”definition) that determine when a project has reached payout are tightly andclearly defined. Environmental “costs of doing business” will continue to berecognized as eligible expenditures.

 

•              No grandfathering will be implemented forexisting oil sands projects.

 

•              Substantial legislative, regulatory and systemsupdates will be introduced before changes become fully effective in January2009.

 

•              The government will implement “shallow rightsreversion” (“**Shallow Rights Reversion**”)to maximize the extraction of resources. Under this policy, mineral rights to shallow gas geological formationsthat are not being developed would revert back to the government and be madeavailable for resale.

 

As at December 31, 2007,approximately 69.9 percent of our total proved gross reserves and approximately68.0 percent of our total proved plus probable gross reserves were located inthe province of Alberta (including the reserves acquired by us pursuant to theVault Acquisition and the Canetic Acquisition). Given that the Proposed Royalty Regime has only recently been announced,it is not possible at this time to determine the full impact of the ProposedRoyalty Regime on our financial condition and operations, and in particular theextent to which the Proposed Royalty Regime will reduce our funds flow, whichwill in turn reduce the cash otherwise available for distribution by us to ourUnitholders.  Penn West’s, Canetic’s andVault’s reserves and the future net revenue associated therewith as summarizedin this Annual Information Form do not reflect the increased royalty ratescontemplated by the Proposed Royalty Regime and, after taking the ProposedRoyalty Regime into account, such values may be adversely affected.

 

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Furthermore, the Report does notcontain any details regarding the implementation of the Alberta government’sproposed Shallow Rights Reversion program. Although the government has indicated that it intends to begin aconsultation process with industry regarding the implementation of the ShallowRights Reversion program, no such consultation process has begun as of the datehereof.  Furthermore, although it is anticipatedthat the Alberta government will give existing leaseholders a grace period tomake their own plans before opening up shallower zones to other industryparticipants, the Alberta government has not provided any indication as to howlong such a grace period might be.  It istherefore not possible at this time to determine the potential impact of theproposed Shallow Rights Reversion program on our financial condition andoperations.

 

We can not provide any assurancethat the Proposed Royalty Regime will be implemented in the form proposed inthe Report.  If changes are made to theProposed Royalty Regime before it is implemented by the Alberta government,such changes could result in the implementation of a new royalty regime thatimpacts us in a materially different manner, and that is more adverse to us,than the royalty regime proposed in the Report.

 

**Additional Financing**

 

In the normal course of makingcapital investments to maintain and expand our oil and gas reserves, additionalTrust Units may be issued which may result in a decline in production per TrustUnit and reserves per Trust Unit. Additionally, from time to time, we may issue Trust Units from treasuryin order to reduce debt and maintain a more optimal capital structure.  Conversely, to the extent that externalsources of capital, including the issuance of additional Trust Units, becomeslimited or unavailable, our ability to make the necessary capital investmentsto maintain or expand our oil and gas reserves will be impaired.  Management believes that the SIFT Tax imposedby the Government of Canada will substantially eliminate the competitiveadvantage that we and other energy trusts have enjoyed relative to our industrycompetitors in raising capital in a tax-efficient manner.  See “Risk Factors – Federal Tax Changes”.  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 flowavailable for distribution to Unitholders will be reduced.

 

**Debt Service**

 

Amounts paid in respect ofinterest and principal on debt we have incurred will reduce funds available fordistributions. Variations in interest rates and any scheduled principalrepayments could result in significant changes in the amount required to beapplied to debt service before payment of the NPIs.  Certain covenants in the agreements with ourlenders may also limit distributions in certain circumstances. Increases ininterest rates 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 andother debt instruments are unsecured and we must comply with certain financialdebt covenants.  The lenders and otherdebt holders could, in the future, require security over a portion of or substantiallyall of our assets.  Should this occur, inthe event that we become unable to pay our debt service charges or otherwisecommit an event of default such as bankruptcy, the lender and other debtholders may foreclose on or require us to sell our oil and gas and otherassets.

 

**Regulatory**

 

Oil and natural gas operations(exploration, production, pricing, marketing and transportation) are subject toextensive controls and regulations imposed by various levels of government thatmay be amended from time to time.  See “IndustryConditions”.  Our operations may requirelicenses from various governmental authorities. There can be no assurance that we will be able to obtain all necessarylicenses and permits that may be required to carry out exploration anddevelopment at our projects.

 

**Operational Matters**

 

Acquiring, developing andexploring for oil and natural gas involves many risks, which even a combinationof experience, knowledge and careful evaluation may not be able toovercome.  These risks include, but arenot limited to, encountering 

 

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unexpected formations orpressures, premature declines of reservoirs, blow-outs, equipment failures andother accidents, sour gas releases, uncontrollable flows of oil, natural gas orwell fluids, adverse weather conditions, pollution, other environmental risks,fires and spills.  Although we maintaininsurance in accordance with customary industry practice based on our projectedcost-benefit analysis of maintaining such insurance, we are not fully insuredagainst all of these risks.  Lossesresulting from the occurrence of these risks could have a material adverseimpact on us.  Like other oil and naturalgas trusts and companies, we attempt to conduct our business and financialaffairs so as to protect against political and economic risks applicable tooperations in the jurisdictions where we operate but there can be no assurancethat we will be successful in so protecting our assets.

 

Continuing production from a property,and to some extent the marketing of production therefrom, are largely dependentupon the ability of the operator of the property.  Operating costs on most properties haveincreased steadily over recent years.  Tothe extent the operator fails to perform these functions properly, operatingincome may be reduced. Payments from production generally flow through theoperator and there is a risk of delay and additional expense in receiving suchrevenues if the operator becomes insolvent. Although satisfactory title reviewsare generally conducted in accordance with industry standards, such reviews donot guarantee or certify that a defect in the chain of title may not arise todefeat our claim to certain of our oil and gas properties. A reduction of theincome available for distributions could result in such circumstances.

 

**Title to Assets**

 

Although title reviews may beconducted prior to the purchase of oil and natural gas producing properties orthe commencement of drilling wells, such reviews do not guarantee or certifythat an unforeseen defect in the chain of title will not arise to defeat ourclaim, which could result in a reduction of the revenue received by theOperating Entities and consequently the funds flow available for distributionto Unitholders.

 

**Expiration of Licenses and Leases**

 

Our properties are held in theform of licenses 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 any 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 affect on our results of operations andbusiness.

 

**Insurance**

 

Our involvement in theexploration for and development of oil and natural gas properties could subjectus to liability for pollution, blowouts, property damage, personal injury orother hazards.  Prior to commencingoperations our operating entities obtain insurance in accordance with industrystandards to address certain of these risks. Such insurance has limitations on liability that may not be sufficientto cover the full extent of such liabilities. In addition, such risks may not, in all circumstances, be insurable or,in certain circumstances, our operating entities may elect not to obtaininsurance to deal with specific risks due to the high premiums associated withsuch insurance or other reasons. The payment of such uninsured liabilitieswould reduce the funds available to us. The occurrence of a significant eventthat we are not fully insured against, or the insolvency of the insurer of suchevent, could have a material adverse effect on our financial position, resultsof operations or prospects and will reduce funds flow otherwise distributableby us.

 

**Maintenance of Distributions**

 

Future oil and natural gasreserves and hence revenues are highly dependent on our Operating Entities’success in exploiting existing properties and acquiring additionalreserves.  We also intend to distributeapproximately 60 percent to 70 percent of our net funds flow to Unitholdersrather than reinvesting it in reserve additions and production growth ormaintenance.  Accordingly, if externalsources of capital, including the issuance of additional Trust Units, becomelimited or unavailable on commercially reasonable terms, our Operating Entities’ability to make the necessary capital investments to maintain or expand theiroil and natural gas reserves will be impaired. To the extent that our Operating Entities are required to use funds flowto finance capital expenditures or property acquisitions, the level of fundsflow available for distribution to Unitholders will be reduced.  Additionally, we cannot guarantee that wewill be successful in exploring for and developing additional reserves oracquiring additional reserves on terms that meet our investmentobjectives.  Without these reserveadditions, our 

 

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reserves will deplete and as aconsequence, either production from, or the average reserve life of, ourproperties will decline. Either decline may result in a reduction in the valueof Trust Units and in a reduction in cash available for distributions toUnitholders.

 

**Delay in Cash Distributions**

 

In addition to the usual delaysin payment by purchasers of oil and natural gas to the operators of theproperties, and by the operator to our Operating Entities, payments between anyof such parties may also be delayed by restrictions imposed by lenders, delaysin the sale or delivery of products, delays in the connection of wells to agathering system, blowouts or other accidents, recovery by the operator ofexpenses incurred in the operation of properties or the establishment by theoperator of reserves for such expenses.

 

**Expansion of Operations**

 

The operations and expertise ofmanagement are currently focused on oil and gas production and exploration anddevelopment in the Western Canadian Sedimentary Basin and, following thecompletion of Canetic Acquisition, in North Dakota, Montana and Wyoming in theUnited States.  In the future, we mayacquire oil 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.

 

**Additional Taxation Applicable to Non-Residents**

 

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

 

Additionally, the reduced “QualifiedDividend” rate of 15 percent tax which has applied to our distributions undercurrent US 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 US government atsuch time.

 

Furthermore, it is anticipatedthat the implementation of the SIFT Tax may have tax consequences forNon-Residents of Canada that are more adverse than the tax consequences toother classes of Unitholders.

 

**Nature of TrustUnits**

 

The Trust Units do not representa traditional 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. Asholders of Trust Units, Unitholders will not have the statutory rights normallyassociated with ownership of shares of a corporation including, for example,the right to bring “oppression” or “derivative” actions.  The rights of Unitholders are specificallyset forth in the Trust Indenture.  Inaddition, trusts are not defined as recognized entities within the definitionsof legislation such as the *Bankruptcy andInsolvency Act* (Canada), the *Companies’Creditors Arrangement Act* (Canada) and in some cases the *Winding Up and Restructuring Act*(Canada).  As a result, in the event ofan insolvency or restructuring, a Unitholder’s position as such may be quitedifferent than that of a shareholder of a corporation.  Our sole assets will be the NPIs and otherinvestments in securities of our Operating Entities, including the InternalNotes. The price per Trust Unit is a function of anticipated income availablefor distributions, the oil and gas assets acquired by us and our ability toeffect long-term growth in the value of our assets.  The market price of the Trust Units will besensitive to a variety of market conditions including, but not limited to,interest rates and our ability to acquire suitable oil and natural gasproperties. Changes in market conditions may adversely affect the trading priceof the Trust Units.

 

**The Trust Units are not “deposits”within the meaning of the *Canada DepositInsurance Corporation Act* (Canada) and are not insured under theprovisions of that Act or any other legislation.  Furthermore, we are not a trust**

 

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**company and, accordingly, weare not registered under any trust and loan company legislation as we do notcarry on or intend to carry on the business of a trust company.**

 

**Unitholder Limited Liability**

 

The Trust Indenture providesthat no Unitholder will be subject to any liability in connection with ourobligations and affairs and, in the event that a court determines Unitholdersare subject to any such liabilities, the liabilities will be enforceable onlyagainst, and will be satisfied only out of, our assets. Pursuant to the TrustIndenture, we will indemnify and hold harmless each Unitholder from any costs,damages, liabilities, expenses, charges and losses suffered by a Unitholderresulting from or arising out of such Unitholder not having such limitedliability.

 

The Trust Indenture providesthat all written instruments signed by or on our behalf must contain aprovision to the effect that such obligation will not be binding uponUnitholders personally. Personal liability may also arise in respect of claimsagainst us that do not arise under contracts, including claims in tort, claimsfor taxes and possibly certain other statutory liabilities. The possibility ofany personal liability of this nature arising is considered unlikely.  The *IncomeTrusts Liability Act* (Alberta) came into force on July 1, 2004.  The legislation provides that a unitholderwill not be, as a beneficiary, liable for any act, default, obligation orliability of the trustee that arises after the legislation came into force.

 

Our operations will beconducted, upon the advice of counsel, in such a way and in such jurisdictionsas to avoid as far as possible any material risk of liability on theUnitholders for claims against us.

 

**Resource Plays – Enhanced Oil Recovery**

 

We currently use conventionalartificial lift technology to recover heavy oil from bitumen deposits at ourPeace River oil sands project.  Thepotential or planned use of enhanced oil recovery (“**EOR**”) methods such as steam injection (Steam Assisted GravityDrainage and Cyclical Steam Stimulation), solvent injection and firefloods toincrease the ultimate recovery of oil resources in place are subject tosignificant risk factors.  These factors,which could lead to a delayed or cancelled EOR application in the Peace Riveroil sands project, include but are not limited to the following:(i) changing economic conditions (commodity pricing, operating and capitalexpenditure fluctuations); (ii) changing engineering and technicalconditions (ability to apply EOR methods to the reservoir and the productionresponse thereto); (iii) the large development program may need to spreadover a longer time period than initially planned due to requirement to allocatecapital expenditures to different periods; (iv) surface access anddeliverability issues (First Nations relations, weather, pipeline, road andprocessing matters); and (v) financing (the availability of sufficientfinancing on acceptable terms).

 

The use or potential or planned use of CO2miscible flooding to increase the oil recovery from large legacy oilpools such as Pembina, South Swan Hills and Midale is subject to significantrisk factors which could lead to the delay or cancellation of some or all ofthese projects.  These factors includebut are not limited to: (i) CO2 infrastructure (the capture andtransportation of the miscible agent to us at an economic cost);(ii) changing economic conditions (commodity pricing, operating andcapital expenditure fluctuations); (iii) changing engineering andtechnical conditions (ability to apply CO2 EOR methods to thereservoir and the production response thereto); (iv) the large developmentprogram may need to be spread over a longer time period than planned due tocapital allocation requirements; (v) surface access and deliverabilityissues (weather, pipeline, road and processing matters); and(vi) financing (the availability of sufficient financing on acceptableterms).

 

**Coalbed Methane (“CBM”) Projects**

 

The engineering, geological,production and associated dewatering techniques employed on CBM projects arerelatively new in the Western Canadian Sedimentary Basin and their applicationto our CBM prone properties is subject to this risk in addition to risk factorssimilar to those listed in the preceding paragraphs related to the Peace Riveroil sands and CO2 miscible flooding.

 

**Dilution**

 

We may make future acquisitionsor enter into financings or other transactions involving the issuance ofsecurities of Penn West, which may be dilutive to Unitholders.  In addition, we may determine to redeem thecurrently outstanding Convertible Debentures for Trust Units or to settle theinterest and/or pay the redemption price at maturity of such Convertible 

 

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Debentures by issuing additionalTrust Units.  Accordingly, holders ofTrust Units may suffer dilution in the event of any such issuance of TrustUnits.

 

**Seasonality**

 

The level of activity in theCanadian oil and gas industry is influenced by seasonal weather patterns.  Wet weather and spring thaw may make theground unstable.  Consequently,municipalities and provincial transportation departments enforce road bans thatrestrict the movement of rigs and other heavy equipment, thereby reducingactivity levels.  Also, certain oil andgas producing areas are located in areas that are inaccessible other thanduring the winter months because the ground surrounding the sites in theseareas consists of swampy terrain. Seasonal factors and unexpected weather patterns may lead to declines inour exploration, development and production activities and thereby adverselyaffect our results of operations and business.

 

**Non-Resident Ownership of Trust Units**

 

In order for us to maintain ourstatus as a mutual fund trust under the Tax Act, we must not be established ormaintained primarily for the benefit of Non-Residents unless we satisfy therequirements 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 interpreted to mean that the majority of unitholders must not beNon-Residents), unless at the relevant time, “all or substantially all” of thetrust’s property consists of property other than taxable Canadian property (the“**TCP Exception**”).  Based on information obtained by us throughour transfer agent and financial intermediaries, in February 2008 (andfollowing the completion of the Vault Acquisition and the Canetic Acquisition),we have estimated that approximately 61 percent of our issued andoutstanding 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 theTCP Exception will continue to be available to us or that the Government ofCanada will not introduce new changes or proposals to tax regulations directedat Non-Resident ownership which, given our level of Non-Resident ownership, mayresult in Penn West losing its mutual fund trust status or could otherwisedetrimentally affect Penn West and the market price of the Trust Units.  PWPL intends to continue to take thenecessary measures in order to ensure Penn West continues to qualify as amutual fund trust under the Tax Act, as it currently exists.  See “Risk Factors – Changes in Legislation”.

 

**Aboriginal Claims**

 

Aboriginal peoples have claimedaboriginal title and rights to portions of western Canada.  We are not aware that any claims have beenmade in respect of our properties and assets; however, if a claim arose and wassuccessful this could have an adverse affect on our results of operations andbusiness.

 

**Availability of Drilling Equipment and Access**

 

Oil and natural gas explorationand development activities are dependent on the availability of drilling andrelated equipment (typically leased from third parties) in the particular areaswhere such 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 will be dependent on such operatorsfor the timing of activities related to such properties and will be largelyunable to direct or control the activities of the operators.

 

**Potential Conflicts of Interest**

 

The directors and officers ofPWPL are engaged in, and will continue to engage in, other activities in theoil and natural gas industry and, as a result of these and other activities,the directors and officers of PWPL may become subject to conflicts ofinterest.  The ABCA provides that in theevent that a director has an interest in a contract or proposed contract oragreement, the director shall disclose his interest in such contract oragreement and shall refrain from voting on any matter in respect of 

 

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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.

 

**Net Asset Value**

 

Our net asset value from time totime will vary depending upon a number of factors beyond the control ofmanagement, including oil and gas prices. The trading prices of the Trust Units from time to time are alsodetermined by a number of factors some of which are beyond the control ofmanagement and such trading prices may be greater or less than our net assetvalue.

 

**Limited Ability of Residents in the United States toEnforce Civil Remedies**

 

Both Penn West and PWPL areorganized under the laws of Alberta, Canada and have their principal place ofbusiness in Canada.  Most of thedirectors and all of the officers of PWPL and the representatives of theexperts who provide services to Penn West and PWPL (such as its auditors andits independent reserve engineers), and a substantial portion of the assets ofPenn West and all or a substantial portion of the assets of such persons arelocated outside the United States.  As aresult, it may be difficult for investors in the United States to effectservice of process within the United States upon such directors, officers andrepresentatives of experts who are not residents of the United States or toenforce against them judgements of the United States courts based upon civilliability under the United States federal securities laws or the securitieslaws of any state within the United States. There is doubt as to the enforceability in Canada against Penn West orPWPL or against any of PWPL’s directors, officers or representatives of expertswho are not residents of the United States, in original actions or in actionsfor enforcement of judgement of United States courts of liabilities basedsolely upon the United States federal securities laws or securities laws of anystate within the United States.

 

**Differences in Reporting Practices in Canada and theUnited States**

 

We report our production andreserve quantities in accordance with Canadian practices and specifically inaccordance with NI 51-101.  Thesepractices are different from the practices used to report production and toestimate reserves in reports and other materials filed with the SEC bycompanies in the United States.

 

We incorporate additionalinformation with respect to production and reserves, which is either notgenerally included or prohibited under rules of the SEC and practices in theUnited States.  We follow the Canadianpractice of reporting gross production and reserve volumes; however, we alsofollow the United States practice of separately reporting these volumes on anet basis (after the deduction of royalties and similar payments).  We also follow the Canadian practice of usingforecast prices and costs when we estimate our reserves.

 

We included in this AnnualInformation Form estimates of proved and proved plus probable reserves.  The SEC generally prohibits the inclusion ofestimates of probable reserves in filings made with it.  This prohibition does not apply to us becausewe are a Canadian foreign private issuer.

 

**Foreign Exchange Risk of Non-Resident Unitholders**

 

Our distributions are declaredin Canadian dollars and converted to foreign denominated currencies at the spotexchange rate at the time of payment.  Asa consequence, investors are subject to foreign exchange risk.  To the extent that the Canadian dollar weakenswith respect to their currency, the amount of the distribution will be reducedwhen converted to their home currency.

 

**Asset Write-Downs**

 

Canadian GAAP requires thatmanagement apply certain accounting policies and make certain estimates andassumptions that affect reported amounts in our consolidated financialstatements.

 

Under Canadian GAAP, the amountsat which petroleum and natural gas property and equipment are carried as netassets on the balance sheet are subject to a cost-recovery or “ceiling” test,which is based in part upon estimated future net funds flows from reserves. Ifnet capitalized costs exceed the estimated recoverable amounts, we will have tocharge the amount of the 

 

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excess to net income.  A decline in the net value of oil and naturalgas properties could cause capitalized costs to exceed the cost ceiling,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 United States GAAP, the estimatedrecoverable amounts are calculated based on estimated future net funds flowsfrom proved reserves discounted at ten percent and using commodity prices ineffect on the balance sheet date.  Theuse of discounting and constant prices results in a greater likelihood of awrite-down under United States GAAP than Canadian GAAP.  See “Risk Factors – Volatility of Oil andNatural Gas Prices”.

 

Canadian GAAP requires thatgoodwill balances be assessed at least annually for impairment and that anypermanent impairment be charged to net income. A permanent reduction inreserves, decline in commodity prices, and/or reduction in the Trust Unit pricemay indicate goodwill impairment.  As atDecember 31, 2007 we had $652.0 million recorded on our balance sheet asgoodwill arising out of the Petrofund Acquisition.  An impairment would result in a write-down ofthe goodwill value and a non-cash charge against net income. The calculation ofimpairment value is subject to management estimates and assumptions.

 

Canadian GAAP in respect ofaccounting for financial instruments may result in non-cash charges againstincome as a result of changes in the fair market value of hedging instruments.A decrease in the fair market value of the hedging instruments as the result offluctuations in commodity prices and/or foreign exchange rates may result in anon-cash charge against income.  Suchnon-cash charges may be temporary in nature if the fair market valuesubsequently increases.

 

**Return of Capital**

 

Trust Units will have no valuewhen the underlying petroleum and natural gas properties can no longer beeconomically produced and, as a result, cash distributions may not represent a “yield”in the traditional sense and are not comparable to bonds or other fixed yieldsecurities, where investors are entitled to a full return of the principalamount of debt on maturity in addition to a return on investment throughinterest payments.  Distributions canrepresent a *return of* or a *return on* Unitholders’ capital.

 

Unitholders have a limited rightto require us to repurchase their Trust Units, which is referred to as aredemption right.  See “InformationRelating to the Trust – Trust Indenture – Right of Redemption”.  It is anticipated that the redemption rightwill not be the primary mechanism for Unitholders to liquidate theirinvestment.  The right to receive cash inconnection with a redemption is subject to limitations.  Any securities which may be distributed *in specie* to Unitholders in connectionwith a redemption may not be listed on any stock exchange and a market may notdevelop for such securities.  Inaddition, there may be resale restrictions imposed by law upon the recipientsof the securities pursuant to the redemption right.

 

**MATERIAL CONTRACTS**

 

Except for contracts enteredinto in the ordinary course of business, the only contracts that are materialto us and that were entered into within the most recently completed financialyear or subsequent thereto, or before the most recently completed financialyear but which are still material and are still in effect, are the following:

 

(a)           the Trust Indenture described under “InformationRelating to the Trust – Trust Indenture”;

 

(b)           the Administration Agreement referred to under “InformationRelating to the Trust – Trust Indenture – Our Management” and “CorporateGovernance”;

 

(c)           the Debenture Indentures described under “InformationRelating to Penn West – Convertible Debentures”;

 

(d)           the credit agreement dated January 10,2008 among PWPL and certain lenders and other parties in respect of Penn West’s$4 billion syndicated credit facility, which agreement is described inNote 5 to Penn West’s financial statements for the year endedDecember 31, 2007, which note is incorporated by reference herein; and

 

(e)           the note purchase agreement dated May 31,2007 among PWPL and the holders of PWPL’s US$475 million principal amount ofnotes, which agreement is described in Note 5 to Penn West’s financialstatements for the year ended December 31, 2007, which note isincorporated by reference herein.

 

57

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Copies of eachof these documents have been filed on SEDAR at www.sedar.com.

 

**LEGAL PROCEEDINGS AND REGULATORY ACTIONS**

** **

There are nolegal proceedings that Penn West is or was a party to, or that any of Penn West’sproperty is or was the subject of, during the most recently completed financialyear, that were or are material to Penn West, and there are no such materiallegal proceedings that Penn West is currently aware of that are contemplated.

 

There wereno:  (i) penalties or sanctionsimposed against Penn West by a court relating to securities legislation or by asecurity regulatory authority during the most recently completed financialyear; (ii) other penalties or sanctions imposed by a court or regulatorybody against Penn West that would likely be considered important to areasonable 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 AND REGISTRARS**

** **

The transferagent and registrar for the Trust Units is CIBC Mellon Trust Company at itsprincipal offices in Calgary, Alberta and Toronto, Ontario.  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, Albertaand Toronto, Ontario.  The transfer agentand registrar for the 6.5% 2006 Debentures, the 8% 2004 Debentures and the 9.4%Debentures is Computershare Trust Company of Canada at its principal offices inCalgary, Alberta and Toronto, Ontario.

 

**INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS**

** **

There were nomaterial interests, direct or indirect, of any director or executive officer ofPWPL, any person or company that beneficially owns, or controls or directs,directly or indirectly, more than 10% of the outstanding Trust Units, or anyknown associate or affiliate of any such person, in any transaction within thethree most recently completed financial years or during the current financialyear that has materially affected or is reasonably expected to materiallyaffect Penn West, except for the matters disclosed in Note 16, Note 17 andunder the heading “Related party transactions” of the consolidated financialstatements for the years ending 2007, 2006 and 2005, which disclosure isincorporated by reference in this Annual Information Form and is filed onSEDAR at www.sedar.com.

 

**INTERESTS OF EXPERTS**

** **

There is noperson or company whose profession or business gives authority to a report,valuation, statement or opinion made by such person or company and who is namedas having prepared or certified a report, valuation, statement or opiniondescribed or included in a filing, or referred to in a filing, made underNational Instrument 51-102 by us during, or related to, our most recentlycompleted financial year (excluding auditors of businesses acquired by us)other than GLJ, our independent engineering evaluator, Sproule, Canetic’s andVault’s independent engineering evaluator (GLJ and Sproule each an “**Engineer**” and collectively the “**Engineers**”),and KPMG LLP, our auditors.  Theregistered or beneficial interests, direct or indirect, in any securities orother property of Penn West or of one of its associates or affiliates:  (i) held by an Engineer and by the “designatedprofessionals” (as defined in National Instrument 51-102) of the Engineer, whenthat Engineer prepared the report, valuation, statement or opinion referred toabove; (ii) received by an Engineer and by the “designated professionals”of that Engineer, after the time specified above; or (iii) to be receivedby an Engineer and by the “designated professionals” of that Engineer; in eachcase, represented less than 1% of each class of our outstandingsecurities.  KPMG LLP is the auditor ofPenn West and is independent within the meaning of the Rules ofProfessional Conduct of the Institute of Chartered Accountants, Alberta.

 

In addition,none of the aforementioned persons or companies, nor any director, officer oremployee of any of the aforementioned persons or companies, is or is expected tobe elected, appointed or employed as a director, officer or employee of PWPL orof any of our associate or affiliate entities. John A. Brussa, the Chairman of PWPL, is a partner of Burnet, Duckworth & Palmer LLP, a law firm which renders legal services to us.

 

58

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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.  Inaddition, additional financial information is provided in Penn West’s financialstatements and management’s discussion and analysis for its most recentlycompleted financial year.

 

Any documentreferred to in this Annual Information Form and described as being filedon SEDAR at www.sedar.com and on EDGAR at www.sec.gov (including thosedocuments referred to as being incorporated by reference in this AnnualInformation Form) may be obtained free of charge from us by contacting ourInvestor Relations Department by telephone (toll free: 1-888-770-2633) or byemail (investor_relations@pennwest.com).

 

59

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**APPENDIXA-1**

 

**REPORTOF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION**

 

**(Form 51-101F3)**

 

Management ofPenn West Petroleum Ltd. (“**PWPL**”) on behalf of PennWest Energy Trust (collectively “**Penn West**”)is responsible for the preparation and disclosure of information with respectto Penn West’s oil and gas activities in accordance with securities regulatoryrequirements. This information includes reserves data which are estimates ofproved reserves and probable reserves and related future net revenue as at December 31,2007, estimated using forecast prices and costs.

 

An independentqualified reserves evaluator has evaluated Penn West’s reserves data. Thereport of the independent qualified reserves evaluator is presented below.

 

The ReservesCommittee of the Board of Directors of PWPL has:

 

(a)                                  reviewed Penn West’sprocedures for providing information to the independent qualified reservesevaluator;

 

(b)                                 met with the independent qualified reservesevaluator to determine whether any restrictions affected the ability of theindependent qualified reserves evaluator to report without reservation; and

 

(c)           reviewed the reserves data withmanagement and the independent qualified reserves evaluator.

 

The ReservesCommittee of the Board of Directors of PWPL has reviewed Penn West’s proceduresfor assembling and reporting other information associated with oil and gasactivities and has reviewed that information with management. The Board ofDirectors has, on the recommendation of the Reserves Committee, approved:

 

(a)                                  the content and filing withsecurities regulatory authorities of Form 51-101F1 containing reservesdata and other oil and gas information;

 

(b)                                 the filing of Form 51-101F2which is the report of the independent qualified reserves evaluator on thereserves data; and

 

(c)                                  the content and filing of thisreport.

 

Because thereserves data are based on judgments regarding future events, actual resultswill vary and the variations may be material. However, any variations should be consistent with the fact that reservesare categorized according to the probability of their recovery.

 
| (signed)  William E. Andrew                          |   | (signed)  Murray R. Nunns                      |
|------------------------------------------------------|--------|------------------------------------------------|
| Chief  Executive Officer                             |   | President  and Chief Operating Officer         |
|                                                 |   |                                           |
| (signed)  Daryl Gilbert                              |   | (signed)  Thomas E. Phillips                   |
| Director and  Chairman****of the Reserves  Committee |   | Director and  Member of the Reserves Committee |
|                                                 |   |                                           |
| March 26,  2008                                 |   |                                           |

 

----

 

**APPENDIXA-2**

 

**GLJREPORT ON RESERVES DATA**

 

**(Form 51-101F2)**

 

To the Boardof Directors of Penn West Petroleum Ltd. (“**PWPL**”)on behalf of Penn West Energy Trust (collectively “**Penn West**”):

 

1.             We have evaluated Penn West’sreserves data as at December 31, 2007. The reserves data are estimates of proved reserves and probable reservesand related future net revenue as at December 31, 2007, estimated usingforecast prices and costs.

 

2.             The reserves data are theresponsibility of PWPL’s management.  Ourresponsibility is to express an opinion on the reserves data based on ourevaluation.

 

We carried out our evaluation in accordancewith standards 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).

 

3.             Those standards require thatwe plan and perform an evaluation to obtain reasonable assurance as to whetherthe reserves data are free of material misstatement.  An evaluation also includes assessing whetherthe reserves data are in accordance with principles and definitions presentedin the COGE Handbook.

 

4.             The following table sets forththe estimated future net revenue (before deduction of income taxes) attributedto proved plus probable reserves, estimated using forecast prices and costs andcalculated using a discount rate of 10 percent, included in the reserves dataof Penn West evaluated by us for the year ended December 31, 2007, andidentifies the respective portions thereof that we have evaluated and reportedon to PWPL’s Board of Directors:

 
| **Independent Qualified**      | ** ** | **Description and   Preparation Date** | ** ** | ** **           | ** ** | **Net Present Value of Future Net Revenue**           | ** ** |
|-------------------------------------|------------|-------------------------------------------------------|------------|----------------------|------------|-------------------------------------------------------------------------------------|------------|
| **Reserves Evaluator or** | ** ** | **of Evaluation**                                | ** ** | **Location of** | ** ** | **(millions before income taxes, 10% discount rate)** | ** ** |
| **Auditor**                         | ** ** | **Report**                                            | ** ** | **Reserves**         | ** ** | **Audited**                                                                         | ** ** | **Evaluated** | ** ** | **Reviewed** | ** ** | **Total** | ** ** |
| GLJ Petroleum                       |       | February 7, 2008                                      |       | Canada               |       | nil                                                                                 |       | $ | 8,100 |   | nil |   | $ | 8,100 |   |
| Consultants Ltd.                    |       |                                                  |       |                 |       |                                                                                |       |   |   |   |   |   |   |
|                                     |            |                                                       |            |                      |            |                                                                                     |            |  |  |  |  |  |  |  |  |

 

5.             In our opinion, the reservesdata respectively evaluated by us have, in all material respects, beendetermined and are in accordance with the COGE Handbook.  We express no opinion on the reserves datathat we reviewed but did not audit or evaluate.

 

6.             We have no responsibility toupdate our reports referred to in paragraph 4 for events and circumstancesoccurring after their respective preparation dates.

 

7.             Because the reserves data arebased on judgements regarding future events, actual results will vary and thevariations may be material.  However, anyvariations should be consistent with the fact that reserves are categorizedaccording to the probability of their recovery.

 

Executed as toour report referred to above:

 

(signed) GLJPetroleum Consultants Ltd.Calgary, AlbertaFebruary 20, 2008

 

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**APPENDIXA-3**

 

**STATEMENT OF RESERVES DATA –PENN WEST ENERGY TRUST**

** **

The Trust’sstatement of reserves data and other oil and gas information is set forth below(the “**Statement**”).  The effective date of the Statement is December 31,2007 and the preparation date of the Statement is March 26, 2008.  The Report of Management and Directors on Oiland Gas Disclosure on Form 51-101F3 and the Report on Reserves Data by GLJon Form 51-101F2 are attached as Appendices A-1 and A-2 to this AnnualInformation Form.

 

**Disclosureof Reserves Data**

** **

The reservesdata set forth below is based upon an evaluation prepared by GLJ with aneffective date of December 31, 2007 contained in the GLJ Report dated February 20,2008.  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 provide an evaluation ofproved and proved plus probable reserves. See also “Notes to Reserve Data Tables” below.

 

**TheGLJ Report does not take into account the new Alberta royalty regime releasedon October 25, 2007 titled *“The NewRoyalty Framework”*, which is scheduled to take effect on January 1,2009, because sufficient details are not yet available for it to be taken intoaccount.  See “Risk Factors – New AlbertaRoyalty Regime”.**

 

Theinformation contained in this Appendix A-3 does not include informationwith respect to the oil and gas properties and reserves of Vault, which wasacquired by Penn West effective January 10, 2008, or Canetic which wasacquired by Penn West effective January 11, 2008.  Information with respect to the oil and gasproperties and reserves of Canetic is set forth in Appendices B-1, B-2 andB-3 to this Annual Information Form.  Inaddition, see “Description of Our Business – Pro Forma Reserves Data of PennWest, Canetic and Vault” for pro forma information in respect of the reservesof Penn West, Canetic and Vault as at December 31, 2007.

 

All of ourreserves are located in Canada and, specifically, in the provinces of Alberta,British Columbia, Saskatchewan and Manitoba.

 

**Itshould not be assumed that the estimates of future net revenues presented inthe tables below represent 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 – Reserve and ResourceEstimates” and “Risk Factors – Volatility of Oil and Natural Gas Prices”.**

 

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**ReservesData (Forecast Prices and Costs)**

** **

SUMMARY OF OIL AND GAS RESERVESas of December 31, 2007FORECAST PRICES AND COSTS

 
| ** **                 | ** ** | **RESERVES**             | ** ** |
|----------------------------|------------|--------------------------|------------|
| ** **                 | ** ** | **LIGHT AND MEDIUM OIL** | ** ** | **HEAVY OIL** | ** ** |
| **RESERVES CATEGORY**      | ** ** | **Gross  (Mbbl)**        | ** ** | **Net  (Mbbl)** | ** ** | **Gross  (Mbbl)** | ** ** | **Net  (Mbbl)** | ** ** |
|                       |       |                     |       |   |   |   |   |   |   |
| PROVED                     |       |                     |       |   |   |   |   |   |   |
| Developed Producing        |       | 151,427                  |       | 137,827 |   | 41,849 |   | 37,852 |   |
| Developed Non-Producing    |       | 4,433                    |       | 4,239 |   | 2,576 |   | 2,189 |   |
| Undeveloped                |       | 34,496                   |       | 31,002 |   | 1,041 |   | 973 |   |
| TOTAL PROVED               |       | 190,355                  |       | 173,069 |   | 45,466 |   | 41,014 |   |
|                       |       |                     |       |   |   |   |   |   |   |
| PROBABLE                   |       | 57,228                   |       | 51,229 |   | 16,383 |   | 14,522 |   |
|                       |       |                     |       |   |   |   |   |   |   |
| TOTAL PROVED PLUS PROBABLE |       | 247,584                  |       | 224,298 |   | 61,849 |   | 55,535 |   |

 
| ** **                 | ** ** | **RESERVES**      | ** ** |
|----------------------------|------------|-------------------|------------|
| ** **                 | ** ** | **NATURAL GAS**   | ** ** | **NATURAL GAS LIQUIDS** | ** ** |
| **RESERVES CATEGORY**      | ** ** | **Gross  (MMcf)** | ** ** | **Net  (MMcf)** | ** ** | **Gross  (Mbbl)** | ** ** | **Net  (Mbbl)** | ** ** |
|                       |       |              |       |   |   |   |   |   |   |
| PROVED                     |       |              |       |   |   |   |   |   |   |
| Developed Producing        |       | 621,130           |       | 510,529 |   | 15,221 |   | 10,554 |   |
| Developed Non-Producing    |       | 43,350            |       | 35,001 |   | 967 |   | 653 |   |
| Undeveloped                |       | 38,483            |       | 31,161 |   | 1,100 |   | 775 |   |
| TOTAL PROVED               |       | 702,963           |       | 576,691 |   | 17,288 |   | 11,982 |   |
|                       |       |              |       |   |   |   |   |   |   |
| PROBABLE                   |       | 197,772           |       | 162,597 |   | 5,136 |   | 3,733 |   |
|                       |       |              |       |   |   |   |   |   |   |
| TOTAL PROVED PLUS PROBABLE |       | 900,734           |       | 739,287 |   | 22,423 |   | 15,715 |   |

 
| ** **                 | ** ** | **RESERVES**             | ** ** |
|----------------------------|------------|--------------------------|------------|
| ** **                 | ** ** | **TOTAL OIL EQUIVALENT** | ** ** |
| **RESERVES CATEGORY**      | ** ** | **Gross  (Mboe)**        | ** ** | **Net  (Mboe)** | ** ** |
|                       |       |                     |       |   |   |
| PROVED                     |       |                     |       |   |   |
| Developed Producing        |       | 312,018                  |       | 271,321 |   |
| Developed Non-Producing    |       | 15,201                   |       | 12,915 |   |
| Undeveloped                |       | 43,051                   |       | 37,944 |   |
| TOTAL PROVED               |       | 370,270                  |       | 322,180 |   |
|                       |       |                     |       |   |   |
| PROBABLE                   |       | 111,709                  |       | 96,583 |   |
|                       |       |                     |       |   |   |
| TOTAL PROVED PLUS PROBABLE |       | 481,979                  |       | 418,763 |   |

 

2

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NET PRESENT VALUESOF FUTURE NET REVENUEBEFORE INCOME TAXES DISCOUNTED AT (%/year)FORECAST PRICES AND COSTS(1)

 
| ** **                 | ** ** | **0%**    | ** ** | **5%**    | ** ** | **10%**   | ** ** | **15%**   | ** ** | **20%**   | ** ** | **Unit Value Before Income    Tax Discounted at   10%/year(2)** | ** ** |
|----------------------------|------------|-----------|------------|-----------|------------|-----------|------------|-----------|------------|-----------|------------|-----------------------------------------------------------------|------------|
| **RESERVES CATEGORY**      | ** ** | **(MM$)** | ** ** | **(MM$)** | ** ** | **(MM$)** | ** ** | **(MM$)** | ** ** | **(MM$)** | ** ** | **($/bbl)**                                                     | ** ** | **($/Mcf)** | ** ** |
|                       |       |      |       |      |       |      |       |      |       |      |       |                                                            |       |   |   |
| PROVED                     |       |      |       |      |       |      |       |      |       |      |       |                                                            |       |   |   |
| Developed Producing        |       | 10,945    |       | 7,543     |       | 5,935     |       | 4,980     |       | 4,336     |       | 21.87                                                           |       | 3.65 |   |
| Developed Non-Producing    |       | 544       |       | 345       |       | 255       |       | 203       |       | 168       |       | 19.74                                                           |       | 3.29 |   |
| Undeveloped                |       | 1,852     |       | 947       |       | 599       |       | 357       |       | 239       |       | 14.74                                                           |       | 2.46 |   |
| TOTAL PROVED               |       | 13,342    |       | 8,836     |       | 6,749     |       | 5,540     |       | 4,743     |       | 20.95                                                           |       | 3.49 |   |
|                       |       |      |       |      |       |      |       |      |       |      |       |                                                            |       |   |   |
| PROBABLE                   |       | 4,714     |       | 2,236     |       | 1,352     |       | 934       |       | 699       |       | 13.99                                                           |       | 2.33 |   |
|                       |       |      |       |      |       |      |       |      |       |      |       |                                                            |       |   |   |
| TOTAL PROVED PLUS PROBABLE |       | 18,055    |       | 11,072    |       | 8,100     |       | 6,474     |       | 5,442     |       | 19.34                                                           |       | 3.22 |   |

 

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Notes:

(1)                                  Management of PWPL hasestimated that the impact of Alberta’s Proposed Royalty Regime, in the formcurrently proposed, is to decrease the net present values of future net revenuebefore income taxes by approximately 3 percent to 4 percent using a10 percent discount rate and using the GLJ forecast prices set forth inthis Annual Information Form.

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

 

NET PRESENTVALUES OF FUTURE NET REVENUEAFTER INCOME TAXES DISCOUNTED AT (%/year)FORECAST PRICES AND COSTS

 
| **RESERVES CATEGORY**      | ** ** | **0%  (MM$)** | ** ** | **5%  (MM$)** | ** ** | **10%  (MM$)** | ** ** | **15%  (MM$)** | ** ** | **20%  (MM$)** | ** ** |
|----------------------------|------------|---------------|------------|---------------|------------|----------------|------------|----------------|------------|----------------|------------|
|                       |       |          |       |          |       |           |       |           |       |           |       |
| PROVED                     |       |          |       |          |       |           |       |           |       |           |       |
| Developed Producing        |       | 9,774         |       | 6,991         |       | 5,620          |       | 4,780          |       | 4,201          |       |
| Developed Non-Producing    |       | 435           |       | 287           |       | 217            |       | 176            |       | 148            |       |
| Undeveloped                |       | 1,417         |       | 740           |       | 443            |       | 285            |       | 191            |       |
| TOTAL PROVED               |       | 11,627        |       | 8,018         |       | 6,280          |       | 5,241          |       | 4,540          |       |
|                       |       |          |       |          |       |           |       |           |       |           |       |
| PROBABLE                   |       | 3,490         |       | 1,702         |       | 1,057          |       | 749            |       | 573            |       |
|                       |       |          |       |          |       |           |       |           |       |           |       |
| TOTAL PROVED PLUS PROBABLE |       | 15,117        |       | 9,720         |       | 7,337          |       | 5,990          |       | 5,113          |       |

 

3

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TOTAL FUTURE NET REVENUE(UNDISCOUNTED)as of December 31, 2007FORECAST 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                |       | 26,741             |       | 3,316                |       | 8,927                       |       | 729                           |       | 427                                               |       | 13,342                                                      |       | 1,715                     |       | 11,627                                                |       |
|                           |       |               |       |                 |       |                        |       |                          |       |                                              |       |                                                        |       |                      |       |                                                  |       |
| Proved Plus Probable  Reserves |       | 35,669             |       | 4,502                |       | 11,529                      |       | 1,108                         |       | 474                                               |       | 18,055                                                      |       | 2,939                     |       | 15,117                                                |       |

 

FUTURE NET REVENUEBY PRODUCTION GROUPas of December 31, 2007FORECAST 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)          |       | 4,267                                                                    |       | 22.20             |   | 3.70 |
|                           |       | Heavy Oil(1)                             |       | 785                                                                      |       | 17.91             |   | 2.98 |
|                           |       | Natural  Gas(2)                          |       | 1,663                                                                    |       | 19.71             |   | 3.28 |
|                           |       | Non-Conventional  Oil and Gas Activities |       | 34                                                                       |       | 19.31             |   | 3.22 |
|                           |       | TOTAL                                    |       | 6,749                                                                    |       | 20.95             |   | 3.49 |
|                           |       |                                     |       |                                                                     |       |              |   |   |
| Proved Plus  Probable Reserves |       | Light and  Medium Crude Oil(1)           |       | 5,074                                                                    |       | 20.46             |   | 3.41 |
|                           |       | Heavy Oil(1)                             |       | 975                                                                      |       | 16.43             |   | 2.74 |
|                           |       | Natural  Gas(2)                          |       | 2,009                                                                    |       | 18.58             |   | 3.10 |
|                           |       | Non-Conventional  Oil and Gas Activities |       | 42                                                                       |       | 16.98             |   | 2.83 |
|                           |       | TOTAL                                    |       | 8,100                                                                    |       | 19.38             |   | 3.23 |

----

Notes:

(1)                                  Including solution gas andother by-products.

(2)                                  Including by-products butexcluding solution gas and by-products from oil wells.

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

 

**Notesto Reserves Data Tables**

** **

1.             Columns may not add due torounding.

 

2.             The crude oil, natural gasliquids and natural gas reserves estimates presented in the GLJ Report arebased on the definitions and guidelines contained in the Canadian Oil and GasEvaluation Handbook (“**COGE Handbook**”).  A summary of those definitions are set forthbelow:

 

**ReservesCategories**

 

Reserves are estimated remaining quantitiesof oil and natural gas and related substances anticipated to be recoverablefrom known accumulations, as of a given date, based on:

 

4

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(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.

 

(a)                                  **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.

 

(b)                                 **Probable reserves** are those additional reserves that are less certain to be recoveredthan proved reserves. It is equally likely that the actual remaining quantitiesrecovered will be greater or less than the sum of the estimated proved plusprobable 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.

 

(a)                                  **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 of drillinga well) to put the reserves on production. The developed category may besubdivided into producing and non-producing.

 

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

 

(ii)           **Developednon-producing reserves** are those reserves thateither have not been on production, or have previously been on production, butare shut-in, and the date of resumption of production is unknown.

 

(b)                                 **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 of production.They must fully meet the requirements of 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. Thisallocation should be based on the estimator’s assessment as to the reservesthat will be recovered from specific wells, facilities and completion intervalsin the pool and their respective development and production status.

 

***L*****evels ofCertainty 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 to the highest level sum of individual entity estimates for whichreserves estimates are presented). Reported reserves should target thefollowing levels of certainty under 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

 

5

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(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, thereshould be no difference between estimates prepared using probabilistic ordeterministic methods.

 

Additional clarificationof certainty levels associated with reserves estimates and the effect ofaggregation 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, 2007,inflation and exchange rates utilized in the GLJ Report were as follows:

 

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONSas of December 31, 2007FORECAST PRICES AND COSTS

 
| ** ** | ** ** | **OIL**                               | ** ** | ** **                                            | ** ** | **EDMONTON LIQUIDS PRICES**        | ** ** | ** **                                    | ** ** | ** **                         | ** ** |
|------------|------------|---------------------------------------|------------|-------------------------------------------------------|------------|----------------------------------------------|------------|-----------------------------------------------|------------|------------------------------------|------------|
| **Year**   | ** ** | **WTI  Cushing  Oklahoma  ($US/bbl)** | ** ** | **Edmonton  Par Price  40oAPI  ($Cdn/bbl)** | ** ** | **Hardisty  Heavy  12oAPI  ($Cdn/bbl)** | ** ** | **Cromer  Medium  29.3oAPI  ($Cdn/bbl)** | ** ** | **NATURAL  GAS  AECO  ($Cdn/Mcf)** | ** ** | **Propane  ($Cdn/bbl)** | ** ** | **Butane  ($Cdn/bbl)** | ** ** | **Pentanes  Plus  ($Cdn/bbl)** | ** ** | **INFLATION  RATES(1)  %/year** | ** ** | **EXCHANGE  RATE(2)  ($ US equals  $1 Cdn)** | ** ** |
|       |       |                                  |       |                                                  |       |                                         |       |                                          |       |                               |       |   |   |   |   |   |   |   |   |   |   |
| Forecast   |       |                                  |       |                                                  |       |                                         |       |                                          |       |                               |       |   |   |   |   |   |   |   |   |   |   |
| 2008       |       | 90.81                                 |       | 89.63                                                 |       | 54.34                                        |       | 77.54                                         |       | 6.63                               |       | 55.30 |   | 69.30 |   | 91.61 |   | — |   | 1.000 |   |
| 2009       |       | 87.00                                 |       | 85.82                                                 |       | 52.01                                        |       | 74.24                                         |       | 7.38                               |       | 52.94 |   | 66.35 |   | 87.71 |   | 2.0 |   | 1.000 |   |
| 2010       |       | 84.33                                 |       | 83.13                                                 |       | 50.38                                        |       | 71.91                                         |       | 7.65                               |       | 51.25 |   | 64.23 |   | 84.97 |   | 2.0 |   | 1.000 |   |
| 2011       |       | 82.39                                 |       | 81.18                                                 |       | 49.18                                        |       | 70.22                                         |       | 7.65                               |       | 50.05 |   | 62.72 |   | 82.97 |   | 2.0 |   | 1.000 |   |
| 2012       |       | 82.13                                 |       | 80.92                                                 |       | 49.02                                        |       | 69.99                                         |       | 7.60                               |       | 49.89 |   | 62.53 |   | 82.70 |   | 2.0 |   | 1.000 |   |
| 2013       |       | 82.40                                 |       | 81.18                                                 |       | 49.71                                        |       | 70.22                                         |       | 7.69                               |       | 50.05 |   | 62.72 |   | 82.97 |   | 2.0 |   | 1.000 |   |
| 2014       |       | 83.23                                 |       | 81.99                                                 |       | 50.74                                        |       | 70.92                                         |       | 7.88                               |       | 50.53 |   | 63.33 |   | 83.80 |   | 2.0 |   | 1.000 |   |
| 2015       |       | 84.08                                 |       | 82.82                                                 |       | 51.78                                        |       | 71.63                                         |       | 8.05                               |       | 51.02 |   | 63.95 |   | 84.66 |   | 2.0 |   | 1.000 |   |
| 2016       |       | 84.94                                 |       | 83.68                                                 |       | 52.84                                        |       | 72.37                                         |       | 8.23                               |       | 51.53 |   | 64.59 |   | 85.53 |   | 2.0 |   | 1.000 |   |
| 2017       |       | 86.65                                 |       | 85.37                                                 |       | 53.92                                        |       | 73.83                                         |       | 8.41                               |       | 52.57 |   | 65.89 |   | 87.26 |   | 2.0 |   | 1.000 |   |
| 2018       |       | 88.38                                 |       | 87.08                                                 |       | 55.00                                        |       | 75.31                                         |       | 8.58                               |       | 53.62 |   | 67.21 |   | 89.00 |   | 2.0 |   | 1.000 |   |
| Thereafter |       | +2                                    | %          | +2                                                    | %          | +2                                           | %          | +2                                            | %          | +2                                 | %          | +2 | % | +2 | % | +2 | % | 2.0 |   | 1.000 |   |

 

----

Notes:

 

(1)                                  Inflation rates forforecasting prices and costs.

(2)                                  Exchange rates used togenerate the benchmark reference prices in this table.

 

6

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Weightedaverage actual prices realized, including hedging activities, for the yearended December 31, 2007 were $7.02/Mcf for natural gas, $69.16/bbl forlight and medium crude oil, $45.26/bbl for heavy oil and $57.37/bbl for naturalgas 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$)**              | ** ** | **Proved Plus Probable  Reserves (MM$)** | ** ** |
|                               |       |                                         |       |   |   |
| 2008                               |       | 199                                          |       | 260 |   |
| 2009                               |       | 134                                          |       | 186 |   |
| 2010                               |       | 95                                           |       | 129 |   |
| 2011                               |       | 72                                           |       | 92 |   |
| 2012                               |       | 47                                           |       | 64 |   |
| Total:  Undiscounted for all years |       | 729                                          |       | 1,108 |   |

 

We currentlyexpect to fund the development costs of the reserves through internallygenerated funds flow withheld from distributions.

 

There can beno guarantee that funds will be available or that we will allocate funding todevelop all of the reserves attributed in the GLJ Report.  Failure to develop those reserves would havea negative impact on future production and funds flow and could result innegative revisions to our reserves.

 

The interestand other costs of any external funding are not included in the reserves andfuture net revenue estimates and would reduce reserves and future net revenueto some degree depending upon the funding sources utilized.  We do not currently anticipate that interestor other funding costs would make development of any property uneconomic.

 

5.                                       Estimated future well abandonment costs related to reserve wellshave been taken into account by GLJ in determining the aggregate future net revenuetherefrom.

 

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

 

7.                                       All factual data supplied to GLJ was accepted as represented. Nofield inspection was conducted.

 

8.                                       **The estimates of future net revenuepresented in the tables above do not represent fair market value.**

 

**Reconciliationsof Changes in Reserves**

** **

The following table sets forth thereconciliation of our gross reserves as at December 31, 2007, usingforecast price and cost estimates derived from the GLJ Report.

 

7

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RECONCILIATION OFCOMPANY GROSS RESERVESBY PRODUCT TYPEFORECAST PRICES AND COSTS

 
| ** **              | ** ** | **LIGHT AND MEDIUM OIL(3)** | ** ** | **HEAVY OIL(3)**       | ** ** | **NATURAL GAS(3)**                   | ** ** |
|-------------------------|------------|--------------------------------------------|------------|-----------------------------|------------|-------------------------------------------|------------|
| **FACTORS**             | ** ** | **Gross  Proved  (Mbbl)**                  | ** ** | **Gross  Probable  (Mbbl)** | ** ** | **Gross  Proved  Plus  Probable  (Mbbl)** | ** ** | **Gross  Proved  (Mbbl)** | ** ** | **Gross  Probable  (Mbbl)** | ** ** | **Gross  Proved  Plus  Probable  (Mbbl)** | ** ** | **Gross  Proved  (MMcf)** | ** ** | **Gross  Probable  (MMcf)** | ** ** | **Gross  Proved  Plus  Probable  (MMcf)** | ** ** |
|                    |       |                                       |       |                        |       |                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |
| December 31,  2006 |       | 186,930                                    |       | 50,880                      |       | 237,810                                   |       | 45,901 |   | 14,031 |   | 59,932 |   | 757,625 |   | 203,213 |   | 960,838 |   |
|                    |       |                                       |       |                        |       |                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Extensions              |       | 169                                        |       | 72                          |       | 241                                       |       | 1,999 |   | 1,062 |   | 3,061 |   | 3,749 |   | 2,494 |   | 6,242 |   |
| Improved  Recovery(1)   |       | 3,124                                      |       | 3,120                       |       | 6,244                                     |       | 2,299 |   | 921 |   | 3,221 |   | 13,306 |   | 1,478 |   | 14,784 |   |
| Technical  Revisions(2) |       | 3,578                                      |       | (686                        | )          | 2,892                                     |       | 1,317 |   | (152 | ) | 1,165 |   | 23,363 |   | (16,648 | ) | 6,716 |   |
| Discoveries             |       | 46                                         |       | 13                          |       | 59                                        |       | 172 |   | 69 |   | 241 |   | 4,202 |   | 1,069 |   | 5,271 |   |
| Acquisitions            |       | 11,990                                     |       | 3,685                       |       | 15,675                                    |       | 1,208 |   | 334 |   | 1,543 |   | 36,037 |   | 13,920 |   | 49,957 |   |
| Dispositions            |       | (348                                       | )          | (109                        | )          | (458                                      | )          | (55 | ) | (23 | ) | (77 | ) | (18,283 | ) | (7,754 | ) | (26,037 | ) |
| Economic  Factors       |       | 935                                        |       | 254                         |       | 1,189                                     |       | 459 |   | 140 |   | 599 |   | — |   | — |   | — |   |
| Production              |       | (16,068                                    | )          | —                      |       | (16,068                                   | )          | (7,835 | ) | — |   | (7,835 | ) | (117,036 | ) | — |   | (117,036 | ) |
|                    |       |                                       |       |                        |       |                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |
| December 31,  2007 |       | 190,355                                    |       | 57,229                      |       | 247,584                                   |       | 45,466 |   | 16,383 |   | 61,849 |   | 702,963 |   | 197,771 |   | 900,734 |   |

 

----

Note:

 

(1)                                  Improved recovery includes thefollowing infill drilling:
| Infill  Drilling |   | 1,355 |   | 1,739 |   | 3,094 |   | 531 |   | 162 |   | 693 |   | 3,652 |   | 1,607 |   | 5,259 |   |
|------------------|--------|-------|--------|-------|--------|-------|--------|-----|--------|-----|--------|-----|--------|-------|--------|-------|--------|-------|--------|

 
| ** **              | ** ** | **NATURAL GAS LIQUIDS(3)** | ** ** | **TOTAL OIL EQUIVALENT(3)** | ** ** |
|-------------------------|------------|--------------------------------------|------------|---------------------------------------|------------|
| **FACTORS**             | ** ** | **Gross  Proved  (Mbbl)**            | ** ** | **Gross  Probable  (Mbbl)**           | ** ** | **Gross  Proved Plus  Probable  (Mbbl)** | ** ** | **Gross  Proved  (Mboe)** | ** ** | **Gross  Probable  (Mboe)** | ** ** | **Gross  Proved Plus  Probable  (Mboe)** | ** ** |
|                    |       |                                 |       |                                  |       |   |   |   |   |   |   |   |   |
| December 31,  2006 |       | 19,590                               |       | 5,303                                 |       | 24,893 |   | 378,692 |   | 104,083 |   | 482,775 |   |
|                    |       |                                 |       |                                  |       |   |   |   |   |   |   |   |   |
| Extensions              |       | 35                                   |       | 11                                    |       | 46 |   | 2,827 |   | 1,560 |   | 4,387 |   |
| Improved  Recovery(1)   |       | 223                                  |       | 108                                   |       | 330 |   | 7,864 |   | 4,395 |   | 12,259 |   |
| Technical  Revisions(2) |       | (679                                 | )          | (385                                  | )          | (1,064 | ) | 8,109 |   | (3,998 | ) | 4,112 |   |
| Discoveries             |       | 73                                   |       | 17                                    |       | 90 |   | 991 |   | 277 |   | 1,268 |   |
| Acquisitions            |       | 565                                  |       | 232                                   |       | 797 |   | 19,770 |   | 6,571 |   | 26,341 |   |
| Dispositions            |       | (424                                 | )          | (150                                  | )          | (574 | ) | (3,874 | ) | (1,574 | ) | (5,448 | ) |
| Economic  Factors       |       | —                               |       | —                                |       | — |   | 1,394 |   | 395 |   | 1,788 |   |
| Production              |       | (2,094                               | )          | —                                |       | (2,094 | ) | (45,503 | ) | — |   | (45,503 | ) |
|                    |       |                                 |       |                                  |       |   |   |   |   |   |   |   |   |
| December 31,  2007 |       | 17,288                               |       | 5,135                                 |       | 22,423 |   | 370,270 |   | 111,709 |   | 481,978 |   |

 

----

Notes:

 

(1)                                  Improved recovery includes thefollowing infill drilling:
| Infill  Drilling |   | 90 |   | 40 |   | 129 |   | 2,584 |   | 2,208 |   | 4,792 |   |
|------------------|--------|----|--------|----|--------|-----|--------|-------|--------|-------|--------|-------|--------|

(2)                                  Technical Revisions includesreclassification of 1,727 Mbbl of proved oil reserves as heavy fromlight/medium and 1,882 Mbbl proved and probable oil reserves as heavy fromlight/medium.

(3)                                  Columns may not add due torounding.

 

8

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**AdditionalInformation Relating to Reserves Data**

** **

***Undeveloped Reserves***

*** ***

Undeveloped reserves are attributed by GLJ inaccordance with standards and procedures contained in the COGE Handbook.  Proved undeveloped reserves are thosereserves that can be estimated with a high degree of certainty and are expectedto be recovered from known accumulations where a significant expenditure isrequired to render them capable of production. Probable undeveloped reserves are those reserves that are less certainto be recovered than proved reserves and are expected to be recovered fromknown accumulations where a significant expenditure is required to render themcapable of production.

 

In some cases, it will take longer than twoyears to develop these reserves.  PennWest plans to develop approximately one-half of the proved undeveloped reservesin the GLJ Report over the next two years and the significant majority of theproved undeveloped reserves over the next five years.** **There are a number offactors that could result in delayed or cancelled development, including thefollowing: (i) changing economic conditions (due to pricing, operating andcapital expenditure fluctuations); (ii) changing technical conditions(including production anomalies, such as water breakthrough or accelerateddepletion); (iii) multi-zone developments (for instance, a prospectiveformation completion may be delayed until the initial completion is no longereconomic); (iv) a larger development program may need to be spread outover several years to optimize capital allocation and facility utilization; and(v) surface access issues (including those relating to land owners,weather conditions and regulatory approvals). For more information, see “Risk Factors”.

 

***Proved Undeveloped Reserves***

*** ***

The following table discloses, for eachproduct type, the gross volumes of proved undeveloped reserves that were firstattributed, net of conversions and revisions, in each of the most recent threefinancial years and, in the aggregate, before that time.

 
| ** **     | ** ** | **Light and Medium Oil  (Mbbl)** | ** ** | **Heavy Oil  (Mbbl)**            | ** ** | **Natural Gas  (MMcf)** | ** ** | **NGLs  (Mbbl)**                      | ** ** |
|----------------|------------|-------------------------------------------------|------------|---------------------------------------|------------|------------------------------|------------|---------------------------------------|------------|
| **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 |       | 12,682                                          |       | 12,682                                |       | 195                          |       | 195                                   |       | 19,064 |   | 19,064 |   | 529 |   | 529 |   |
| 2005           |       | 3,420                                           |       | 16,102                                |       | —                       |       | 195                                   |       | 2,122 |   | 21,186 |   | 117 |   | 646 |   |
| 2006           |       | 13,081                                          |       | 29,183                                |       | 210                          |       | 405                                   |       | 5,632 |   | 26,818 |   | 160 |   | 806 |   |
| 2007           |       | 5,313                                           |       | 34,496                                |       | 636                          |       | 1,041                                 |       | 11,665 |   | 38,483 |   | 294 |   | 1,100 |   |

 

GLJ has assigned 43 MMboe of provenundeveloped reserves in the GLJ Report under forecast prices and costs,together with $450.9 million of associated undiscounted future capitalexpenditures.  Proven undeveloped capitalspending in the first two forecast years of the GLJ Report accounts for $233.1million, or 52 percent, of the total forecast. These figures increase to $392.8 million or 87 percent, during the firstfive years of the GLJ Report.  Themajority of Penn West’s proven undeveloped reserves evaluated in the GLJ Reportare attributable to future oil development from CO2 injection,infill drilling, water injection and miscible fluid injection enhanced oilrecovery (“**EOR**”) projects.

 

The Pembina Cardium pool is currentlydeveloped primarily on 80 acre well spacing units.  Penn West believes that much of the poolcould be economically developed on 40 acre spacing units or throughhorizontal drilling.  Some of thereserves associated with these additional locations have been included in theGLJ Report as proven undeveloped reserves.

 

Penn West holds interests in CO2 injection EOR properties in SE Saskatchewanand Central Alberta, a hydrocarbon injection EOR property in the Swan Hillsarea, operates a CO2 injection EOR project on theJoffre Viking Tertiary Oil Unit and a hydrocarbon injection EOR project in theSouth Swan Hills Unit.  Development offuture miscible and CO2 injection EOR reserves isscheduled over several years in order to maximize the use of existinginfrastructure and available injectants.

 

For further information, see “Risk Factors –Resource Plays – Enhanced Oil Recovery”.

 

9

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***Probable Undeveloped Reserves***

*** ***

The following table discloses, for eachproduct type, the gross volumes of probable undeveloped reserves that werefirst attributed, net of conversions and revisions, in each of the most recentthree financial years and, in the aggregate, before that time.

 
| ** **     | ** ** | **Light and Medium Oil  (Mbbl)** | ** ** | **Heavy Oil  (Mbbl)**            | ** ** | **Natural Gas  (MMcf)** | ** ** | **NGLs  (Mbbl)**                      | ** ** |
|----------------|------------|-------------------------------------------------|------------|---------------------------------------|------------|------------------------------|------------|---------------------------------------|------------|
| **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 |       | 1,022                                           |       | 1,022                                 |       | 4                            |       | 4                                     |       | 1,607 |   | 1,607 |   | 53 |   | 53 |   |
| 2005           |       | 7,324                                           |       | 8,346                                 |       | 548                          |       | 552                                   |       | 8,220 |   | 9,827 |   | 551 |   | 604 |   |
| 2006           |       | 10,524                                          |       | 18,870                                |       | 151                          |       | 703                                   |       | 4,896 |   | 14,723 |   | 975 |   | 1,579 |   |
| 2007           |       | 5,290                                           |       | 24,160                                |       | 729                          |       | 1,432                                 |       | 10,896 |   | 25,619 |   | 257 |   | 1,836 |   |

 

GLJ has assigned 32 MMboe of probableundeveloped reserves, which are primarily associated with proved undevelopedreserve assignments but have a less likely probability of being recovered thansuch associated proved undeveloped reserve assignments.

 

***Significant Factors or Uncertainties***

*** ***

The development schedule of Penn West’sundeveloped reserves is based on forecast price assumptions for thedetermination of economic projects.  Theactual prices that occur may be significantly lower or higher resulting in someprojects being delayed or accelerated, as the case may be.  See “Risk Factors – Volatility of Oil andNatural Gas Prices”.

 

Penn West does not anticipate that anysignificant economic factors or other significant uncertainties will affect anyparticular components of its reserves data. However, Penn West’s reserves can be affected significantly byfluctuations in product pricing, capital expenditures, operating costs, royaltyregimes and well performance that are beyond our control.

 

***Additional Information Concerning Abandonment and Reclamation Costs***

*** ***

Overall costs are based on well boreabandonment and reclamation costs and liability issues such as flare pitremediation, and facility decommissioning, remediation, and reclamationcosts.  These costs were estimated usingPenn West’s experience conducting annual abandonment and reclamation programsover the past several years.

 

Penn West reviews suspended or standing wellbores for reactivation, recompletion or sale and conducts systematicabandonment programs for those well bores that do not meet our criteria.  A portion of Penn West’s liability issues areretired every year and facilities are decommissioned when all the wellsproducing to them have been abandoned. All of Penn West’s liability reduction programs take into accountseasonal access, high priority and stakeholder issues, and opportunities formulti-location programs to reduce costs.

 

Penn West’s total inventory is estimated at15,319 net well bores and 1,267 facilities as of December 31, 2007.  Penn West expects to incur abandonment andreclamation costs in respect to all of these wells, facilities and otherproperties associated with these operations.

 

The total amount of abandonment andreclamation costs, net of estimated salvage values, that Penn West expects toincur, including wells that extend beyond the 50-year limit in the GLJ Report,are summarized in the following 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, 2007 |       | 1,873                                                                                                    |       | 209                                                                                                                     |       |
|                                          |       |                                                                                                     |       |                                                                                                                    |       |
| Anticipated  to be paid in 2008               |       | 40                                                                                                       |       | 36                                                                                                                      |       |
| Anticipated  to be paid in 2009               |       | 42                                                                                                       |       | 35                                                                                                                      |       |
| Anticipated  to be paid in 2010               |       | 44                                                                                                       |       | 33                                                                                                                      |       |

 

10

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The above table includes certain abandonmentand reclamation costs, net of salvage values, not included in the GLJ Reportand not deducted in estimating future net revenue as disclosed earlier in thisAnnual Information Form.  Escalated attwo percent and undiscounted, the costs not deducted were $1,399 million, andescalated at two percent and discounted at 10 percent, these costs were$156 million.

 

**OTHER OIL AND GAS INFORMATION**

** **

Our portfolio of properties asat December 31, 2007 includes both unitized and non-unitized oil andnatural gas production.  In general, theproperties contain long-life, low-decline rate reserves and include interestsin several major oil and gas fields.

 

**PrincipalProperties**

** **

The following is a descriptionof our principal oil and natural gas properties as at December 31,2007.  Reserve amounts are stated at December 31, 2007, based on forecast cost and price assumptionsas evaluated in the GLJ Report prepared by GLJ. Information in respect of gross and net acres and well counts is as at December 31,2007, and information in respect of production is for the year ended December 31,2007 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, 2007 may not directlycorrespond to the stated production for the year, which only includesproduction since the date the interests were acquired by us.  The estimates of reserves and future netrevenue for individual properties may not reflect the same confidence level asestimates of reserves and future net revenue for all properties, due to theapplication of statistical methods of aggregating individual properties.

 

All of the properties describedbelow are located in the Western Canadian Sedimentary Basin and within theCanadian provinces of British Columbia, Alberta,Saskatchewan or Manitoba.  The propertiesrepresent 100 percent of the total net proved plus probable reserves as assigned by GLJ in theGLJ Report.** **There are no material properties to which reserves have beenattributed which are capable of producing but which are not producing.

 

**Major Operating Regions**

** **

The following table shows Penn West’s reported average daily production and provedplus probable reserves, as at December 31, 2007, by major core region:

 
| ** ** | ** ** | **Average Daily Production**           | ** ** | **Proved Plus Probable Gross Reserves** | ** ** | ** **               | ** ** |
|------------|------------|--------------------------------------------------|------------|-------------------------------------------------------------|------------|--------------------------|------------|
| ** ** | ** ** | **Crude Oil  and NGLs********(bbl/d)** | ** ** | **Natural Gas**** ****(MMcf/d)**                  | ** ** | **Total********(boe/d)** | ** ** | **Crude Oil  and NGLs********(MMbbl)** | ** ** | **Natural  Gas**** ****(Bcf)** | ** ** | **Total********(MMboe)** | ** ** | **Undeveloped********Land********(000 net acres)** | ** ** |
| Central    |       | 36,709                                           |       | 137                                                         |       | 59,435                   |       | 187.4 |   | 379.9 |   | 250.7 |   | 1,253 |   |
| Plains     |       | 35,195                                           |       | 89                                                          |       | 50,048                   |       | 133.9 |   | 259.3 |   | 177.2 |   | 964 |   |
| Northern   |       | 1,820                                            |       | 106                                                         |       | 19,509                   |       | 10.5 |   | 261.5 |   | 54.1 |   | 1,008 |   |
| Total      |       | 73,724                                           |       | 332                                                         |       | 128,992                  |       | 331.9 |   | 900.7 |   | 482.0 |   | 3,225 |   |
|       |       | 57% ofdaily  production                          |       | 43 % of  daily  production                                  |       |                     |       | 69 % of  total  reserves |   | 31 % of  total  reserves |   |   |   |   |   |
|            |            |                                                  |            |                                                             |            |                          |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

** **

**Oil and Natural Gas Properties**

** **

Penn West’sproduction and reserves are attributed to more than 200 producingproperties.  No single property accountsfor more than 10 percent of Penn West’s reserves.  A general discussion of our operations andactivities in each of our core areas follows.

 

***Northern Area***

*** ***

The NorthernArea currently provides approximately 32 percent of Penn West’s naturalgas production and two percent of its liquids production, based on 2007 exitrate production.  Geographically, thearea encompasses the land base north of Township 90 in Alberta and extends intothe Peace River Arch and Northeastern regions of British Columbia.  Approximately 39 percent of the Northern Area’sgas is produced from the Wildboy field in Northeast British Columbia.  Gas 

 

11

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is producedfrom two primary zones in Wildboy: the Mississippianat a depth of approximately 600 metres, and the Jean Marie at approximately1,300 metres.  Penn West has netundeveloped land holdings of approximately 1,008,000 acres in theNorthern Area.

 

The exploration and development of the 100percent owned Wildboy field followed a Penn West discovery in 1995.  Since then, development of the field hascontinued through the drilling of horizontal and vertical wells, the additionof field booster compression, gas processing plant expansion and theconstruction of a sales gas line into Alberta to accommodate the increased volumes.  Raw throughput of the facility averaged 42 MMcf/dfor 2007.

 

Penn West drilled four wells in the NorthernArea in 2007, with 2008 plans focusing on improving field compression andwellbore optimization.  In Wildboy, PennWest acquired 74,000 acres of Crown land prospective for shale gas underlyingour Wildboy infrastructure. In 2008, Penn West will begin evaluating theacreage with three dimensional seismic and drilling a stratigraphic testwell.  The Peace River Arch areacurrently provides approximately three percent of Penn West’s totalproduction.  In 2007, Penn West drilledfour wells in the Buick Creek area. Plans for 2008 are focused on wellbore optimization at Firebird, SpiritRiver and Cecil Lake, with plans to drill locations for natural gas in theHalfway and Montney formations.  PennWest currently holds approximately 76,000 net acres of undeveloped land in thePeace River Arch area.

 

***Central Area***

*** ***

The CentralArea currently provides approximately 41 percent of Penn West’s natural gasproduction and 50 percent of its liquids production based on 2007 exit rateproduction.  The region contains large,long-life pools of Cardium light oil, oil sands deposits in the Peace River OilSands area and shallow to medium-depth, multi-zone natural gas pools.  This region is both an established producingarea and an area of significant potential reserves and productiongrowth.  Penn West’s long-life, lowdecline rate Cardium oil reserves in the Central Area provide a stable sourceof premium quality light oil.  Cardiumoil receives a price very close to the Edmonton par price.  Penn West holds approximately 1,253,000 netacres of undeveloped land in the Central Area.

 

The CentralArea is also a significant natural gas producing area, with production of 137MMcf/d at year-end 2007.  The natural gasprospects in the area tend to be multi-zone and relatively liquids rich.  Penn West’s control of several natural gasprocessing facilities throughout the area allows Penn West to gain economies ofscale in the surrounding natural gas operations.  One of our principal facilities in theCentral Area is the Minnehik-Buck Lake natural gas processing facility in whichPenn West controls a majority interest. The facility has the capacity to process over 120 MMcf/d of natural gasincluding the capability to process sour natural gas.

 

*Central – Peace River Oil Sands*

* *

Since 2002, Penn West has grown its land base toapproximately 300,000 net acres of 100 percent owned oil sands leases in thePeace River oil sands area.  As of theend of 2007, we have drilled 81 horizontal wells and 36 stratigraphic wells inthe focus areas of Seal Main, Seal North and Cadotte.  In 2006, Penn West acquired a 35 percentworking interest in a 13,500 bbl/d facility and a 15 percent working interestin a 55,000 bbl/d pipeline.  In 2008, 24stratigraphic wells and 20 to 25 net horizontal wells are planned, with capitalprograms of approximately $55 million, excluding acquisitions.

* *

*Central – Pembina*

* *

Pembinaproduces high-netback, long-life, low-decline light oil and liquids-richnatural gas.  Approximately 1,222operated producing wellbores account for 12,100 bbl/dof operated production or nine percent of our 2007 production.  Our share of current Pembina area productionis approximately 16,350 boe/d including operated and non-operated volumes.

 

The group of properties is centred on theextensive, long-life Cardium oil pool. The pool is in the secondary recovery (water flood) phase and iscontinuously being optimized.  Our EOR team iscurrently expanding the Cardium CO2 pilot to include a new pattern incorporatinghorizontal producing wells.  The pilotexpansion should be completed and operational during the second quarter of2008.

 

The Pembina team’s overall focus is on low-risk drilling and low-costoptimization opportunities that are aimed at adding value to the Trust’sUnitholders and reinvesting capital for Penn West’s long-term resourceplays.  Costs are kept down to

 

12

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increase netbacks by exploiting Penn West’slarge network of operated infrastructure, which includes an extensive networkof gas plants, numerous oil batteries and thousands of kilometres of oil andgas gathering lines.

 

The Pembina Cardium pool is relativelylightly-drilled with many opportunities for conventional exploration anddevelopment of shallow through deep targets. Pembina has an array of multizone potential throughout the area,includingthe Edmonton Sands, Belly River, Cardium, Glauconite, Ellerslie, Rock Creek,Pekisko, Banff and some deep Nisku.

 

Penn Westdrilled 14 gross wells in 2007, with plans for a 2008 drilling program of 16wells.  This drilling program is a mix ofshallow Edmonton gas wells, low-risk Cardium infill wells, development wells andmedium depth gas wells.  As in 2007, PennWest continues to strive to improve efficiency of operations to maximize oiland gas recovery through the use of geological and reservoir studies and enhanced recoverymethods.

 

*Central - Willesden Green*

* *

Located southof Pembina, Willesden Green is an area of long-life and low-decline light oiland liquids-rich natural gas from multiple zones.  Penn West has a strategic advantage in thearea by having operational control over key infrastructure.

 

WillesdenGreen is an active development area.  The12 development and exploitation wells planned in 2008 (up from six wellsin 2007) are intended to offset natural productiondeclines.  We retain deep mineral rightsthroughout the area, enhancing longer-term exploration potential for Penn Westor drilling partners.

 

The productionfrom the Willesden Green area has remained relatively constant through oil andgas well drilling and optimization of the area’s wells and infrastructure.  In addition, the area has one of our highestnetbacks due to its mix of light oil, liquids rich natural gas, low royaltyrates and relatively low net operating costs. Penn West controls the area’s oil and natural gas gatheringinfrastructure that is centred on our 100 percent-owned Willesden Greengas plant. In 2006, Penn West de-bottlenecked its gas gathering and gasprocessing infrastructure, increasing the plant’s capacity to process additional Penn West and third-party volumes.

 

In 2007, six infillwells were drilled focusing on the 100 percent working interest Cardiumoil and Belly River natural gas pools. For 2008, we planto drill 12 wells focusing on low risk Cardium infill drilling, liquids richManville gas wells and shallow Edmonton gas wells.

 

*Central – Swan Hills*

* *

Penn Westholds a majority interest in the South Swan Hills Unit, as well as otherinterests in the area.  South Swan Hillsis a light oil pool where a combination of water and miscible hydrocarboninjection is used to increase recovery factors.

 

The South SwanHills Unit is also the site of two pilot projects: the Mannville horizontalcoal bed methane (“**CBM**”) project,which is currently beginning production operations and the SwanHills CO2 pilot, which is currently under construction.

 

The CBM pilothas been on production for approximately six months.  The pilot wells are currently in thedewatering phase and are performing as expected.  Based on industry production experience atthe offsetting successful Corbett Creek CBM property, the dewatering processcould take between six and 12 months for the initial pilot wells,shortening as development takes place and the coals are de-pressured.  Pending the success of the pilot project,full-scale CBM development could take place over the next fouryears.

 

The planned CO2 pilot in South Swan Hills will target portionsof the Swan Hills reef complex that have only been partially miscible floodedin the past.  The pilot, which consistsof two “five spot” patterns, is under construction and will be operationalduring the second quarter of 2008.  Thispilot will also help in the evaluation of the potential of using CO2 flooding in the East Swan Hills Unit, whichhas not undergone any miscible flooding to date, but is geologically similar tothe CO2 pilot area.

 

13

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***Plains Area***

*** ***

The PlainsArea is a shallow depth all season access region with multi-zone potential thatsupplies 27 percent of Penn West’s natural gas production and 48 percent of theliquids based on 2007 exit rate production. In 2007, Penn West drilled 112 net wellsin this area.  Target zones include theBakken, Mannville and Viking.  Extensive2D and 3D seismic is used to select drilling locations.  Penn West owns and operates an extensiveinfrastructure of gas plants, batteries and pipelines in the Plains Area.  In 2008, Penn West plans to drill 155 netwells and holds approximately 964,000 net acres of undeveloped land in thearea.

 

*Plains – Wainright*

* *

Keycharacteristics of the Wainright property group include: extensive developedand undeveloped lands, high working interests, low-decline heavy oil and Vikingnatural gas production, and widespread infrastructure.  These advantages allow Penn West tocontinually optimize operations while adding new production at low risk andcost throughout the area.

 

In 2007,investment of $8.7 million funded 125 separate optimization projects.  Development drilling added 685 boe/d in newvolumes and the optimization projects added 800 boe/d.  Complemented by properties at Sugden,Consort, and Ribstone acquired with the Petrofund Acquisition, the Wainwrightgroup of properties generated overall volumes of 17,300 boe/d or approximately13.5 percent of our 2007 exit production.

 

*Plains – Hoosier – Coleville*

* *

Hoosier andColeville consist of more than 29 producing properties and form one of PennWest’s most active development areas. These assets, mainly operated by Penn West, include approximately 2,757producing wellbores, a high average working interest, extensive Penn Westinfrastructure and a combined 943,000 acres of lands, of which 348,000 netacres are undeveloped.

 

Hoosier’sprimary commodity is cold-pumped conventional heavy oil.  The main geological targets are theseismically defined Bakken formation, the Mannville Group and the extensiveViking formation, all at depths shallower than 850 metres.  Penn West drilled 49 wells throughoutHoosier in 2007, including 35 vertical wells, five horizontal wellsand nine natural gas wells.  In theColeville Bakken pool, Penn West initiated a program during 2007 to replace allof the aging pipeline infrastructure. This program will reduce our exposure to environmental liability byreducing the frequency of pipeline breaks and capturing otherwise ventedsolution gas.  Also, the improvedinfrastructure will allow us to further optimize the waterflood scheme bytargeting water injection to specific areas of the reservoir.

 

In 2008, PennWest has budgeted $38 million to drill 47 vertical wells and six horizontalwells in Hoosier.  The main focus will beoil development driven by the scope of medium-term opportunities rather thanshort-term price volatility.

 

*Plains – South and Other Area*

* *

The PlainsSouth Area is a proven producing region with long-life medium and light oilreserves from a variety of stratigraphic zones producing a total ofapproximately 8,500 bbl/d.  Theseproperties stretch from the Rocky Mountains to western Manitoba and 200kilometres north from the US border. This large geographic region includes many opportunities for developmentand optimization.

 

Penn West acquired a 21.1 percent interest inthe Weyburn Unit located in Southeast Saskatchewan in the PetrofundAcquisition.  Weyburn is Canada’s largestcommercial CO2 enhanced oilrecovery project, producing approximately 26,500 bbl/d (approximately 5,650bbl/d net to Penn West) at December 31, 2007, sourcing CO2 for injection from a coal gasification plantin North Dakota.  Our share of capitalcosts was $51 million in 2007 decreasing to approximately $46 million in 2008.  The application of CO2 miscible flooding increased therecovery factor from 31 percent under a secondary waterflood scheme to 48percent under the CO2 enhanced recoveryscheme.  With the Petrofund Acquisition,we also increased our working interest in the Midale Unit to approximately 8.7percent where CO2 flooding will occurusing the same CO2 source as Weyburn.

 

14

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*** ***

***Additional Information***

*** ***

None of Penn West’s importantproperties, plants, facilities or installations are subject to any material statutory or other mandatory relinquishments,surrenders, back-ins or changes in ownership.

 

For a discussion of properties to whichreserves have been attributed and which are capable of producing but which arenot producing, see “Additional Information Relating to Reserves Data –Undeveloped Reserves” above.

 

**Oil And Gas Wells**

** **

The following table sets forth the number andstatus of wells in which we had a working interest as at December 31,2007.

 
| ** **        | ** ** | **Producing** | ** ** | **Non-Producing** | ** ** | **Total**  | ** ** |
|-------------------|------------|---------------|------------|-------------------|------------|------------|------------|
| ** **        | ** ** | **Oil**       | ** ** | **Gas**           | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **        | ** ** | **Gross**     | ** ** | **Net**           | ** ** | **Gross**  | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
|              |       |          |       |              |       |       |       |   |   |   |   |   |   |   |   |   |   |
| Alberta           |       | 7,649         |       | 4,132             |       | 4,301      |       | 2,262 |   | 5,432 |   | 3,016 |   | 17,382 |   | 9,410 |   |
| British  Columbia |       | 92            |       | 24                |       | 630        |       | 318 |   | 270 |   | 129 |   | 992 |   | 471 |   |
| Saskatchewan      |       | 4,956         |       | 3,360             |       | 665        |       | 547 |   | 2,244 |   | 1,343 |   | 7,865 |   | 5,250 |   |
| Manitoba          |       | 145           |       | 138               |       | —     |       | — |   | 56 |   | 51 |   | 201 |   | 189 |   |
| Total             |       | 12,842        |       | 7,654             |       | 5,596      |       | 3,127 |   | 8,002 |   | 4,539 |   | 26,440 |   | 15,320 |   |

** **

**Properties with no Attributed Reserves**

** **

The following table sets out the unprovedproperties in which we have an interest as at December 31, 2007.

 

| ** **       | ** ** | **Unproved Properties  (000s of Acres)** | ** ** |
|------------------|------------|---------------------------------------------------------|------------|
| ** **       | ** ** | **Gross**                                               | ** ** | **Net** | ** ** |
|             |       |                                                    |       |   |   |
| Alberta          |       | 2,555                                                   |       | 2,148 |   |
| British Columbia |       | 514                                                     |       | 421 |   |
| Saskatchewan     |       | 551                                                     |       | 517 |   |
| Manitoba         |       | 140                                                     |       | 139 |   |
| Total            |       | 3,760                                                   |       | 3,225 |   |

 

We currently have no material workcommitments on these lands.  The primarylease or extension term on 598,114 net acresof unproved property will expire by December 31, 2008.  The right to explore, develop and exploitthese leases will be surrendered unless we qualify them for continuation basedon existing production, 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 currently expectedthat no income tax liability will be incurred provided we maintain thisorganizational structure.  To the extentthat taxable income is retained in our Operating Entities to fund capitalexpenditures or repay bank debt, it is possible that income taxes could bepayable 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 “Risk Factors – Federal Tax Changes”.

 

15

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** **

**Capital Expenditures**

** **

The following table summarizes capitalexpenditures (net of incentives and net of certain proceeds) related to ouractivities for the year ended December 31, 2007.

 

| ** **             | ** ** | **2007  MM$** | ** ** |
|------------------------|------------|---------------|------------|
|                   |       |          |       |
| Property Acquisitions  |       |          |       |
| Proved Properties      |       | $             | 421.7      |   |
| Unproved Properties    |       | 30.2          |       |
| Exploration Costs(1)   |       | 102.0         |       |
| Development Costs(2)   |       | 529.5         |       |
| Corporate Costs        |       | 35.6          |       |
| Capital Expenditures   |       | $             | 1,119.0    |   |
| Corporate Acquisitions |       | 21.2          |       |
| Total Expenditures     |       | $             | 1,140.2    |   |

 

----

Notes:

 
| (1) | Costs  of land acquired, geological and geophysical capital expenditures and  drilling costs for 2007 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, 2007.

 

| ** **  | ** ** | **Exploratory Wells** | ** ** | **Development Wells** | ** ** |
|-------------|------------|----------------------------|------------|----------------------------|------------|
| ** **  | ** ** | **Gross**                  | ** ** | **Net**                    | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Oil         |       | 21                         |       | 19                         |       | 159 |   | 89 |   |
| Natural Gas |       | 28                         |       | 22                         |       | 86 |   | 33 |   |
| Service     |       | 17                         |       | 17                         |       | 22 |   | 13 |   |
| Dry         |       | 4                          |       | 3                          |       | 4 |   | 3 |   |
| Total       |       | 70                         |       | 61                         |       | 271 |   | 138 |   |

 

We estimate capital expenditures of approximately$910 million in 2008 to execute our capital programs. The primarycomponents of our programs are described under the heading “Other Oil and Gasinformation – Oil and Natural Gas Properties”.

 

**Production Estimates**

** **

The following table sets out the volume ofour production estimated for the year ended December 31, 2008 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**   | ** ** |
|--------------------------------|------------|-------------------------------------|------------|--------------------|------------|----------------------|------------|-------------------------------|------------|-------------|------------|
| ** **                     | ** ** | **(bbl/d)**                         | ** ** | **(bbl/d)**        | ** ** | **(Mcf/d)**          | ** ** | **(bbl/d)**                   | ** ** | **(boe/d)** | ** ** |
| ** **                     | ** ** | **Gross**                           | ** ** | **Net**            | ** ** | **Gross**            | ** ** | **Net**                       | ** ** | **Gross**   | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Proved Producing               |       | 40,203                              |       | 35,228             |       | 20,786               |       | 17,990                        |       | 279,199     |       | 221,772 |   | 5,593 |   | 3,862 |   | 113,114 |   | 94,042 |   |
| Proved Developed Non-Producing |       | 812                                 |       | 719                |       | 442                  |       | 353                           |       | 11,086      |       | 8,613 |   | 189 |   | 131 |   | 3,290 |   | 2,638 |   |
| Proved Undeveloped             |       | 1,684                               |       | 1,415              |       | 487                  |       | 427                           |       | 3,792       |       | 2,730 |   | 96 |   | 71 |   | 2,899 |   | 2,368 |   |
| Total Proved                   |       | 42,698                              |       | 37,361             |       | 21,715               |       | 18,770                        |       | 294,078     |       | 233,116 |   | 5,878 |   | 4,064 |   | 119,303 |   | 99,048 |   |
| Total Probable                 |       | 1,672                               |       | 1,337              |       | 1,376                |       | 1,119                         |       | 15,250      |       | 11,446 |   | 209 |   | 146 |   | 5,800 |   | 4,510 |   |
| Total Proved Plus Probable     |       | 44,371                              |       | 38,698             |       | 23,091               |       | 19,890                        |       | 309,328     |       | 244,562 |   | 6,087 |   | 4,210 |   | 125,103 |   | 103,558 |   |

 

16

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No property accounts for more thannine percent of the estimated production disclosed above.  For more information, see “Other Oil and GasInformation – Principal Properties”.

 

**Production History**

** **

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

 
| ** **                               | ** ** | **Quarter Ended 2007** | ** ** | **Year Ended** | ** ** |
|------------------------------------------|------------|----------------------------------|------------|---------------------|------------|
| ** **                               | ** ** | **Mar. 31**                 | ** ** | **June 30**    | ** ** | **Sept. 30** | ** ** | **Dec. 31** | ** ** | **Dec. 31, 2007** | ** ** |
| Average Daily Production(1)              |       |                             |       |                |       |   |   |   |   |   |   |
| Light and Medium Crude Oil (bbl/d)       |       | 42,737                           |       | 44,078              |       | 45,046 |   | 45,338 |   | 44,310 |   |
| Heavy Oil (bbl/d)                        |       | 22,610                           |       | 21,288              |       | 21,922 |   | 22,262 |   | 22,019 |   |
| Gas (MMcf/d)                             |       | 340.4                            |       | 334.1               |       | 315.4 |   | 328.1 |   | 329.4 |   |
| NGLs (bbl/d)                             |       | 6,369                            |       | 5,558               |       | 5,815 |   | 5,732 |   | 5,866 |   |
| Combined (boe/d)                         |       | 128,447                          |       | 126,599             |       | 125,345 |   | 128,024 |   | 127,098 |   |
|                                     |       |                             |       |                |       |   |   |   |   |   |   |
| Average Net Production Prices Received   |       |                             |       |                |       |   |   |   |   |   |   |
| Light and Medium Crude Oil ($/bbl)       |       | 60.93                            |       | 66.57               |       | 74.49 |   | 78.20 |   | 70.26 |   |
| Heavy Oil ($/bbl)                        |       | 41.03                            |       | 42.45               |       | 48.75 |   | 48.69 |   | 45.26 |   |
| Gas ($/Mcf)                              |       | 7.59                             |       | 7.55                |       | 5.86 |   | 6.34 |   | 6.85 |   |
| NGLs ($/bbl)                             |       | 49.81                            |       | 54.71               |       | 58.10 |   | 67.38 |   | 57.37 |   |
| Combined ($/boe)                         |       | 50.08                            |       | 52.63               |       | 52.73 |   | 55.44 |   | 52.73 |   |
|                                     |       |                             |       |                |       |   |   |   |   |   |   |
| Royalties Paid                           |       |                             |       |                |       |   |   |   |   |   |   |
| Light and Medium Crude Oil ($/bbl)       |       | 9.78                             |       | 10.37               |       | 11.46 |   | 12.07 |   | 10.95 |   |
| Heavy Oil ($/bbl)                        |       | 6.27                             |       | 6.38                |       | 7.32 |   | 7.18 |   | 6.79 |   |
| Gas ($/Mcf)                              |       | 1.67                             |       | 1.64                |       | 1.25 |   | 1.34 |   | 1.48 |   |
| NGLs ($/bbl)                             |       | 17.24                            |       | 18.57               |       | 19.49 |   | 22.51 |   | 19.41 |   |
| Combined ($/boe)                         |       | 9.63                             |       | 9.82                |       | 9.46 |   | 9.97 |   | 9.72 |   |
|                                     |       |                             |       |                |       |   |   |   |   |   |   |
| Production Costs (2)(3)                  |       |                             |       |                |       |   |   |   |   |   |   |
| Light and Medium Crude Oil ($/bbl)       |       | 15.37                            |       | 15.55               |       | 15.41 |   | 15.73 |   | 15.52 |   |
| Heavy Oil ($/bbl)                        |       | 12.09                            |       | 12.15               |       | 12.17 |   | 12.32 |   | 12.18 |   |
| Gas ($/Mcf)                              |       | 1.04                             |       | 1.10                |       | 1.15 |   | 1.17 |   | 1.12 |   |
| NGLs ($/bbl)                             |       | 13.63                            |       | 13.14               |       | 13.49 |   | 14.15 |   | 13.61 |   |
| Combined ($/boe)                         |       | 10.70                            |       | 10.94               |       | 11.18 |   | 11.35 |   | 11.04 |   |
|                                     |       |                             |       |                |       |   |   |   |   |   |   |
| Transportation                           |       |                             |       |                |       |   |   |   |   |   |   |
| Light and Medium Crude Oil ($/bbl)       |       | —                           |       | —              |       | — |   | — |   | — |   |
| Heavy Oil ($/bbl)                        |       | 0.08                             |       | 0.03                |       | 0.12 |   | 0.06 |   | 0.07 |   |
| Gas ($/Mcf)                              |       | 0.20                             |       | 0.20                |       | 0.18 |   | 0.21 |   | 0.20 |   |
| NGLs ($/bbl)                             |       | —                           |       | —              |       | — |   | — |   | — |   |
| Combined ($/boe)                         |       | 0.53                             |       | 0.52                |       | 0.47 |   | 0.56 |   | 0.52 |   |
|                                     |       |                             |       |                |       |   |   |   |   |   |   |
| (Gain)/Loss on Risk Management Contracts |       |                             |       |                |       |   |   |   |   |   |   |
| Light and Medium Crude Oil ($/bbl)       |       | (0.41                            | )          | —              |       | 0.27 |   | 4.36 |   | 1.10 |   |
| Heavy Oil ($/bbl)                        |       | —                           |       | —              |       | — |   | — |   | — |   |
| Gas ($/Mcf)                              |       | (0.06                            | )          | (0.01               | )          | (0.43 | ) | (0.20 | ) | (0.17 | ) |
| NGLs ($/bbl)                             |       | —                           |       | —              |       | — |   | — |   | — |   |
| Combined ($/boe)                         |       | (0.29                            | )          | (0.03               | )          | (0.98 | ) | 1.02 |   | (0.06 | ) |

 

17

----

 
| ** **                         | ** ** | **Quarter Ended 2007** | ** ** | **Year Ended** | ** ** |
|------------------------------------|------------|----------------------------------|------------|---------------------|------------|
| ** **                         | ** ** | **Mar. 31**                 | ** ** | **June 30**    | ** ** | **Sept. 30** | ** ** | **Dec. 31** | ** ** | **Dec. 31, 2007** | ** ** |
| Netback Received(4)                |       |                             |       |                |       |   |   |   |   |   |   |
| Light and Medium Crude Oil ($/bbl) |       | 36.19                            |       | 40.65               |       | 47.35 |   | 46.04 |   | 42.69 |   |
| Heavy Oil ($/bbl)                  |       | 22.59                            |       | 23.89               |       | 29.14 |   | 29.13 |   | 26.22 |   |
| Gas ($/Mcf)                        |       | 4.74                             |       | 4.62                |       | 3.71 |   | 3.82 |   | 4.22 |   |
| NGLs ($/bbl)                       |       | 18.94                            |       | 23.00               |       | 25.12 |   | 30.72 |   | 24.35 |   |
| Combined ($/boe)                   |       | 29.51                            |       | 31.38               |       | 32.60 |   | 32.54 |   | 31.51 |   |

 

----

Notes:

 

(1)                                  Before deduction of royalties.

(2)                                  Operating expenses arecomposed of direct costs incurred to operate both oil and gas wells.  A number of assumptions are required toallocate these costs between oil, natural gas and natural gas liquidsproduction.

(3)                                  Operating recoveriesassociated with operated properties are charged to operating costs andaccounted for as a reduction to general and administrative costs.

(4)                                  Netbacks are calculated bysubtracting royalties, operating costs, transportation and losses/gains oncommodity and foreign exchange contracts from revenues.

 

**Marketing andFuture Commitments**

** **

Our marketing approachincorporates 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 2007, Penn West received an average pricefrom the sale of natural gas, including hedging gains, of $7.02/Mcfcompared to $7.47/Mcf realized in 2006. Approximately 87 percent of our natural gas sales are marketed directly with thebalance 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 to conservativelymanage our transportation costs. Transportation on all pipelines is closely balanced tosupply, and market commitments related to export transportation representedless than two percent of sales.

 

***Oil and Liquids Marketing***

*** ***

The average quality of our crudeoil production is 28 degrees API. Approximately 62 percent of our liquidsproduction can be attributed to light and medium oil, with an average API of 36degrees. Conventional heavy oil, at 15 degrees average API, comprisesapproximately 30 percent of total liquids production.  Production of NGLs account for approximatelyeight percent of total liquids production.

 

We market our production at the lease levelon varying term contracts that capture premiums on postings for the majority ofcorporate sales and actively manage our heavy oil supply by findingopportunities to optimize netbacks through blending, 

 

18

----

 

trucking and proprietary handling ofemulsion. Blending costs are also controlled through the use of proprietary condensatesupply.

 

The following table summarizesthe net product price received for our production of conventional light andmedium oil and conventional heavy oil for the periods indicated:

 
| ** **             | ** ** | **2007**                            | ** ** | **2006**           | ** ** |
|------------------------|------------|-------------------------------------|------------|--------------------|------------|
| ** **             | ** ** | **Light and  Medium Oil** | ** ** | **Heavy Oil** | ** ** | **Light and  Medium Oil** | ** ** | **Heavy Oil** | ** ** |
| **Quarter ended** | ** ** | **($/bbl)**                         | ** ** | **($/bbl)**        | ** ** | **($/bbl)** | ** ** | **($/bbl)** | ** ** |
|                   |       |                                |       |               |       |   |   |   |   |
| March 31          |       | 60.93                               |       | 41.03              |       | 63.42 |   | 30.76 |   |
| June 30           |       | 66.57                               |       | 42.45              |       | 73.20 |   | 52.85 |   |
| September 30      |       | 74.49                               |       | 48.75              |       | 72.27 |   | 52.20 |   |
| December 31       |       | 78.20                               |       | 48.69              |       | 58.51 |   | 37.57 |   |

*** ***

***ForwardContracts***

*** ***

Our Board of Directors approved a policy thatenables us to hedge up to 50 percent of our liquids and natural gas priceexposure (net of royalties) for a maximum of two years and up to75 percent for a maximum of one year. As at December 31, 2007, Penn West was not bound by any agreement(including a transportation agreement), directly or through an aggregator,under which it may be precluded from fully realizing, or may be protected fromthe full effect of, future market prices for oil or natural gas, except for thefollowing financial hedging positions that were outstanding as at December 31,2007:

 
| ** **                    | ** ** | **Notional Volume** | ** ** | **Remaining Term** | ** ** | **Pricing**                 | ** ** | **Market Value(1)  (MM$ )** | ** ** |
|-------------------------------|------------|--------------------------|------------|-------------------------|------------|-----------------------------|------------|---------------------------------------|------------|
| **Crude Oil Collars**         |       |                     |       |                    |       |                        |       |                                  |       |
| WTI Collars                   |       | 10,000 bbl/d             |       | Jan/08 – Jun/08    |       | US$ 60.00 to 94.55/bbl |       | $                                     | (9.2       | ) |
| WTI Collars                   |       | 20,000 bbl/d             |       | Jan/08 – Dec/08    |       | US$ 67.50 to 79.18/bbl |       | (109.8                                | )          |
| WTI Collars                   |       | 10,000 bbl/d             |       | Jul/08 – Dec/08    |       | US$ 67.00 to 79.23/bbl |       | (24.9                                 | )          |
|                          |       |                     |       |                    |       |                        |       |                                  |       |
| **Natural Gas Collars**       |       |                     |       |                    |       |                        |       |                                  |       |
| AECO Collars                  |       | 10,000 GJ/d              |       | Jan/08 – Mar/08    |       | $7.50 to $11.15/GJ          |       | 1.1                                   |       |
| AECO Collars                  |       | 50,000 GJ/d              |       | Jan/08 – Oct/08    |       | $6.00 to $7.15/GJ           |       | (0.7                                  | )          |
| AECO Collars                  |       | 50,000 GJ/d              |       | Apr/08 – Oct/08    |       | $6.06 to $6.60/GJ           |       | (2.0                                  | )          |
|                          |       |                     |       |                    |       |                        |       |                                  |       |
| **Electricity Swaps**         |       |                     |       |                    |       |                        |       |                                  |       |
| Alberta Power Pool            |       | 32 MW                    |       | 2008                    |       | $75.02/MWh                  |       | —                                |       |
| Alberta Power Pool            |       | 30 MW                    |       | 2009                    |       | $76.23/MWh                  |       | 0.1                                   |       |
| Alberta Power Pool            |       | 30 MW                    |       | 2010                    |       | $76.23/MWh                  |       | (0.7                                  | )          |
|                          |       |                     |       |                    |       |                        |       |                                  |       |
| **Interest Rate Swaps**       |       |                     |       |                    |       |                        |       |                                  |       |
|                          |       | $100.0  million          |       | Jan/08 – Mar/08    |       | 4.356%                      |       | 0.3                                   |       |
|                          |       | $100.0  million          |       | Jan/08 – Nov/10    |       | 4.264%                      |       | —                                |       |
|                          |       |                     |       |                    |       |                        |       |                                  |       |
| **Foreign Exchange Forwards** |       |                     |       |                    |       |                        |       |                                  |       |
| 8-year term                   |       | US$80.0 million          |       | 2015                    |       | 1.00934 CAD/USD             |       | (0.6                                  | )          |
| 10-year term                  |       | US$80.0 million          |       | 2017                    |       | 1.00165 CAD/USD             |       | (0.6                                  | )          |
| 12-year term                  |       | US$70.0 million          |       | 2019                    |       | 0.99125 CAD/USD             |       | (0.2                                  | )          |
| 15-year term                  |       | US$20.0 million          |       | 2022                    |       | 0.98740 CAD/USD             |       | (0.4                                  | )          |
|                          |       |                     |       |                    |       |                        |       |                                  |       |
|                          |       |                     |       |                    |       |                        |       | $                                     | (147.6     | ) |

 

----

Note:

 

(1)                                  Unrealized gain (loss) basedon calculations using posted rates for similar contracts on December 31,2007.

 

Our transportation obligations andcommitments for future physical deliveries of crude oil and natural gas do notexceed our expected related future production from our proved reserves,estimated using forecast prices and costs.

 

19

----

*** ***

***FutureCommitments***

*** ***

We have committed to certain payments overthe next five years, in addition to regular payments under our creditfacilities, as follows:

 
| **($ millions)**   | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** | **2012** | ** ** | **Thereafter** | ** ** |
|-------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------|------------|
| Long-term debt          |       | —   |       | —   |       | 1,485.4  |       | —   |       | —   |       | 457.8          |       |
| Transportation          |       | 13.9     |       | 5.8      |       | 2.2      |       | 0.1      |       | —   |       | —         |       |
| Transportation ($US)    |       | 2.3      |       | 2.3      |       | 2.3      |       | 2.3      |       | 2.3      |       | 6.4            |       |
| Power Infrastructure    |       | 6.2      |       | 4.2      |       | 4.2      |       | 4.2      |       | 4.2      |       | 7.6            |       |
| Drilling Rigs           |       | 7.7      |       | 2.4      |       | 1.2      |       | —   |       | —   |       | —         |       |
| Purchase Obligations(1) |       | 13.3     |       | 13.3     |       | 13.3     |       | 13.3     |       | 13.2     |       | 41.1           |       |
| Office Lease            |       | 19.4     |       | 19.6     |       | 17.3     |       | 16.5     |       | 16.2     |       | 104.3          |       |

 

----

Note:

(1)                                 These amounts representestimated commitments of $84.4 million for CO2purchases and $23.1 million for processing fees related tointerests in the Weyburn unit.

 

20

----

** **

**APPENDIXB-1**

** **

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

 

**(Form 51-101F3)**

 

Management of Penn West Petroleum Ltd. (“**PWPL**”) on behalf of Canetic Resources Trust (“**Canetic**”) is responsible for the preparation and disclosure ofinformation with respect to Canetic’s oil and gas activities in accordance withsecurities regulatory requirements. This information includes reserves datawhich are estimates of proved reserves and probable reserves and related futurenet revenue as at December 31, 2007, estimated using forecast prices andcosts.

 

An independent qualified reserves evaluatorhas evaluated Canetic’s reserves data. The report of the independent qualifiedreserves evaluator is presented below.

 

The Reserves Committee of the Board ofDirectors of PWPL has:

 

(b)                                 reviewed Canetic’s procedures for providing information to theindependent qualified reserves evaluator;

 

(b)                                 met with the independent qualified reserves evaluator to determinewhether any restrictions affected the ability of the independent qualifiedreserves evaluator to report without reservation; and

 

(c)                                  reviewed the reserves data with management and the independentqualified reserves evaluator.

 

The Reserves Committee of the Board ofDirectors of PWPL has reviewed Canetic’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 therecommendation of the Reserves Committee, 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 evaluator 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) Thomas E. Phillips                    |
| Director and Chairman****of the Reserves Committee |   | Director and Member of the Reserves  Committee |
|                                               |   |                                           |
| March 26, 2008                                |   |                                           |

 

----

 

**APPENDIXB-2**

** **

**SPROULE REPORT ONRESERVES DATA**

 

**(Form 51-101 F2)**

 

To the Board of Directors of Penn WestPetroleum Ltd. (“**PWPL**”) on behalfof Canetic Resources Trust (“**Canetic**”):

 

1.                                       We have evaluated Canetic’s reserves data as at December 31,2007.  The reserves data are estimates ofproved reserves and probable reserves and related future net revenue as at December 31,2007, estimated using forecast prices and costs.

 

2.                                       The reserves data are the responsibility of PWPL’s management.  Our responsibility is to express an opinionon the reserves data based on our evaluation.

 

We carried out our evaluation in accordancewith standards 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).

 

3.                                       Those standards require that we plan and perform an evaluation toobtain reasonable assurance as to whether the reserves data are free ofmaterial misstatement.  An evaluation alsoincludes assessing whether the reserves data are in accordance with principlesand definitions presented in the COGE Handbook.

 

4.                                       The following table sets forth the estimated future net revenue(before deduction of income taxes) attributed to proved plus probable reserves,estimated using forecast prices and costs and calculated using a discount rateof 10 percent, included in the reserves data of Canetic evaluated by us for theyear ended December 31, 2007, and identifies the respective portionsthereof that we have evaluated and reported on to PWPL’s Board of Directors:

 
| **Independent Qualified  Reserves Evaluator or** | ** ** | **Description and  Preparation Date  of Evaluation ** | ** ** | **Location of** | ** ** | **Net Present Value of Future Net Revenue  (millions before income taxes, 10% discount rate)** | ** ** |
|-----------------------------------------------------------------|------------|---------------------------------------------------------------------------|------------|----------------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|
| **Auditor**                                                     | ** ** | **Report**                                                                | ** ** | **Reserves**         | ** ** | **Audited**                                                                                                                                                | ** ** | **Evaluated** | ** ** | **Reviewed** | ** ** | **Total** | ** ** |
| Sproule Associates Limited                                      |       | March 3, 2008                                                        |       | Canada               |       | nil                                                                                                                                                        |       | $ | 4,362 |   | nil |   | $ | 4,362 |   |
|                                                                 |            |                                                                           |            |                      |            |                                                                                                                                                            |            |  |  |  |  |  |  |  |  |

 

5.                                       In our opinion, the reserves data respectively evaluated by us have,in all 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.

 

6.                                       We have no responsibility to update our reports referred to inparagraph 4 for events and circumstances occurring after their respectivepreparation dates.

 

7.                                       Because the reserves data are based on judgements regarding futureevents, actual results 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) Sproule Associates Limited Calgary, Alberta

 

March 3, 2008

 

----

** **

**APPENDIXB-3**

** **

**STATEMENTOF RESERVES DATA – CANETIC RESOURCES TRUST**

** **

Canetic’s statement of reserves data andother oil and gas information is set forth below (the “**Statement**”).  The effective date of the Statement is December 31,2007 and the preparation date of the Statement is March 26, 2008.  The Report of Management and Directors on Oiland Gas Disclosure on Form 51-101F3 and the Report on Reserves Data bySproule on Form 51-101F2 are attached as Appendices B-1 and B-2 to thisAnnual Information Form.

 

**Disclosure of Reserves Data**

** **

The reserves data set forth below is basedupon an evaluation prepared by Sproule with an effective date of December 31,2007 contained in the Sproule Canetic Report dated March 3, 2008.  The reserves data summarizes Canetic’s oil,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 Sproule to provide an evaluationof proved and proved plus probable reserves. See also “Notes to Reserve Data Tables” below.

 

**The Sproule Canetic Report doesnot take into account the new Alberta royalty regime released on October 25,2007 titled *“The New Royalty Framework”*,which is scheduled to take effect on January 1, 2009, because sufficientdetails are not yet available for it to be taken into account.  See “Risk Factors – New Alberta RoyaltyRegime”.**

 

The majority of Canetic’s reserves arelocated in Canada and, specifically, in the provinces of Alberta, BritishColumbia, Saskatchewan and Manitoba. Canetic also has minor interests in the United States.

 

**It should not be assumed that theestimates of future net revenues presented in the tables below represent thefair market value of the reserves.  Thereis no assurance that the forecast prices and costs assumptions will be attainedand variances could be material.  Therecovery and reserves estimates of crude oil, natural gas liquids and naturalgas reserves provided herein are estimates only and there is no guarantee thatthe estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquid reserves may begreater than or less than the estimates provided herein.  For more information as to the risksinvolved, see “Risk Factors – Reserve and Resource Estimates” and “Risk Factors– Volatility of Oil and Natural Gas Prices”.**

 

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

** **

The reserves information presented does notreport the US reserves separately.  The USproperties have proved plus probable gross reserves of approximately 6,151Mboe, or 2.5 percent of Canetic’s total reserves, and have a before tax netpresent value discounted at 10 percent of approximately $76.9 million, or 1.8percent of the total value of Canetic’s reserves.

 

SUMMARY OF OIL AND GAS RESERVESas of December 31, 2007FORECAST PRICES AND COSTS

 

| ** **                 | ** ** | **RESERVES**                            | ** ** |
|----------------------------|------------|-----------------------------------------|------------|
| ** **                 | ** ** | **LIGHT AND MEDIUM OIL** | ** ** | **HEAVY OIL** | ** ** |
| **RESERVES CATEGORY** | ** ** | **Gross  (Mbbl)**                       | ** ** | **Net  (Mbbl)** | ** ** | **Gross  (Mbbl)** | ** ** | **Net  (Mbbl)** | ** ** |
| ** **                 | ** ** | ** **                              | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| PROVED                     |       |                                    |       |   |   |   |   |   |   |
| Developed Producing        |       | 75,945                                  |       | 68,518 |   | 14,195 |   | 12,908 |   |
| Developed Non-Producing    |       | 834                                     |       | 744 |   | 463 |   | 395 |   |
| Undeveloped                |       | 3,543                                   |       | 3,213 |   | 484 |   | 429 |   |
| TOTAL PROVED               |       | 80,322                                  |       | 72,475 |   | 15,142 |   | 13,732 |   |
|                       |       |                                    |       |   |   |   |   |   |   |
| PROBABLE                   |       | 30,459                                  |       | 27,192 |   | 4,220 |   | 3,783 |   |
| TOTAL PROVED PLUS PROBABLE |       | 110,781                                 |       | 99,666 |   | 19,362 |   | 17,515 |   |

 

----

 

| ** **                 | ** ** | **RESERVES**         | ** ** |
|----------------------------|------------|----------------------|------------|
| ** **                 | ** ** | **NATURAL GAS** | ** ** | **NATURAL GAS LIQUIDS** | ** ** |
| **RESERVES CATEGORY** | ** ** | **Gross  (MMcf)**    | ** ** | **Net  (MMcf)** | ** ** | **Gross  (Mbbl)** | ** ** | **Net  (Mbbl)** | ** ** |
| ** **                 | ** ** | ** **           | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| PROVED                     |       |                 |       |   |   |   |   |   |   |
| Developed Producing        |       | 360,249              |       | 283,443 |   | 10,994 |   | 7,767 |   |
| Developed Non-Producing    |       | 22,813               |       | 17,301 |   | 385 |   | 281 |   |
| Undeveloped                |       | 20,162               |       | 15,516 |   | 259 |   | 172 |   |
| TOTAL PROVED               |       | 403,224              |       | 316,260 |   | 11,638 |   | 8,221 |   |
|                       |       |                 |       |   |   |   |   |   |   |
| PROBABLE                   |       | 194,709              |       | 153,250 |   | 4,785 |   | 3,386 |   |
| TOTAL PROVED PLUS PROBABLE |       | 597,932              |       | 469,510 |   | 16,423 |   | 11,606 |   |

 

| ** **                 | ** ** | **RESERVES**                       | ** ** |
|----------------------------|------------|------------------------------------|------------|
| ** **                 | ** ** | **TOTAL OIL EQUIVALENT** | ** ** |
| **RESERVES CATEGORY** | ** ** | **Gross  (Mboe)**                  | ** ** | **Net  (Mboe)** | ** ** |
| ** **                 | ** ** | ** **                         | ** ** | ** ** | ** ** |
| PROVED                     |       |                               |       |   |   |
| Developed Producing        |       | 161,176                            |       | 136,434 |   |
| Developed Non-Producing    |       | 5,484                              |       | 4,303 |   |
| Undeveloped                |       | 7,646                              |       | 6,399 |   |
| TOTAL PROVED               |       | 174,306                            |       | 147,137 |   |
|                       |       |                               |       |   |   |
| PROBABLE                   |       | 71,915                             |       | 59,902 |   |
| TOTAL PROVED PLUS PROBABLE |       | 246,221                            |       | 207,039 |   |

 

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

FORECASTPRICES AND COSTS(1)

 
| ** **                 | ** ** | ** **    | ** ** | ** **    | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** | **Unit Value Before Income  Tax Discounted at 10%/year(2)** | ** ** |
|----------------------------|------------|---------------|------------|---------------|------------|----------------|------------|----------------|------------|----------------|------------|-------------------------------------------------------------------------------------------|------------|
| **RESERVES CATEGORY** | ** ** | **0%  (MM$)** | ** ** | **5%  (MM$)** | ** ** | **10%  (MM$)** | ** ** | **15%  (MM$)** | ** ** | **20%  (MM$)** | ** ** | **($/bbl)**                                                                               | ** ** | **($/Mcf)** | ** ** |
| ** **                 | ** ** | ** **    | ** ** | ** **    | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** | ** **                                                                                | ** ** | ** ** | ** ** |
| PROVED                     | ** ** | ** **    | ** ** | ** **    | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** | ** **                                                                                | ** ** | ** ** | ** ** |
| Developed Producing        |       | 5,429         |       | 4,023         |       | 3,266          |       | 2,789          |       | 2,457          |       | 23.94                                                                                     |       | 3.99 |   |
| Developed Non-Producing    |       | 123           |       | 98            |       | 82             |       | 70             |       | 61             |       | 19.05                                                                                     |       | 3.18 |   |
| Undeveloped                |       | 169           |       | 130           |       | 101            |       | 79             |       | 62             |       | 15.73                                                                                     |       | 2.62 |   |
| TOTAL PROVED               |       | 5,721         |       | 4,251         |       | 3,449          |       | 2,938          |       | 2,579          |       | 23.44                                                                                     |       | 3.91 |   |
|                       |       |          |       |          |       |           |       |           |       |           |       |                                                                                      |       |   |   |
| PROBABLE                   |       | 2,502         |       | 1,380         |       | 913            |       | 666            |       | 516            |       | 15.23                                                                                     |       | 2.54 |   |
|                       |       |          |       |          |       |           |       |           |       |           |       |                                                                                      |       |   |   |
| TOTAL PROVED PLUS PROBABLE |       | 8,223         |       | 5,631         |       | 4,362          |       | 3,604          |       | 3,095          |       | 21.07                                                                                     |       | 3.51 |   |

 

----

Notes:

 

(1)                                 Management of PWPL hasestimated that the impact of Alberta’s Proposed Royalty Regime, in the formcurrently proposed, is to decrease the net present values of future net revenuebefore income taxes by approximately 2 percent to 3 percent using a 10 percentdiscount rate and using the Sproule forecast prices set forth in this AnnualInformation Form.

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

 

2

----

 

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

FORECAST PRICES AND COSTS

 
| **RESERVES CATEGORY**  | ** ** | **0%  (MM$)** | ** ** | **5%  (MM$)** | ** ** | **10%  (MM$)** | ** ** | **15%  (MM$)** | ** ** | **20%  (MM$)** | ** ** |
|-----------------------------|------------|---------------|------------|---------------|------------|----------------|------------|----------------|------------|----------------|------------|
|                        |       |          |       |          |       |           |       |           |       |           |       |
| PROVED                      |       |          |       |          |       |           |       |           |       |           |       |
| Developed  Producing        |       | 5,133         |       | 3,886         |       | 3,194          |       | 2,747          |       | 2,431          |       |
| Developed  Non-Producing    |       | 106           |       | 87            |       | 74             |       | 64             |       | 57             |       |
| Undeveloped                 |       | 159           |       | 122           |       | 95             |       | 74             |       | 58             |       |
| TOTAL PROVED                |       | 5,398         |       | 4,095         |       | 3,363          |       | 2,886          |       | 2,546          |       |
|                        |       |          |       |          |       |           |       |           |       |           |       |
| PROBABLE                    |       | 1,960         |       | 1,105         |       | 746            |       | 555            |       | 437            |       |
|                        |       |          |       |          |       |           |       |           |       |           |       |
| TOTAL PROVED  PLUS PROBABLE |       | 7,357         |       | 5,200         |       | 4,109          |       | 3,441          |       | 2,983          |       |

 

TOTAL FUTURE NET REVENUE(UNDISCOUNTED)as of December 31, 2007FORECAST 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                |       | 11,455             |       | 1,708                |       | 3,495                       |       | 160                           |       | 371                                             |       | 5,721                                                  |       | 323                      |       | 5,398                                                 |       |
|                           |       |               |       |                 |       |                        |       |                          |       |                                            |       |                                                   |       |                     |       |                                                  |       |
| Proved Plus Probable  Reserves |       | 16,557             |       | 2,501                |       | 5,112                       |       | 292                           |       | 428                                             |       | 8,223                                                  |       | 866                      |       | 7,357                                                 |       |

 

FUTURE NET REVENUEBY PRODUCTION GROUPas of December 31, 2007FORECAST 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)                |       | 2,282                                                                   |       | 26.40             |   | 4.40 |
|                          |       | Heavy Oil(1)                                  |       | 269                                                                     |       | 18.90             |   | 3.15 |
|                          |       | Natural Gas(2)                                |       | 865                                                                     |       | 19.70             |   | 3.28 |
|                          |       | Non-Conventional Oil and Gas Activities (CBM) |       | 34                                                                      |       | 12.90             |   | 2.15 |
|                          |       | TOTAL                                         |       | 3,450                                                                   |       | 23.40             |   | 3.90 |
|                          |       |                                          |       |                                                                    |       |              |   |   |
| Proved Plus Probable Reserves |       | Light and Medium Crude Oil(1)                 |       | 2,832                                                                   |       | 23.80             |   | 3.97 |
|                          |       | Heavy Oil(1)                                  |       | 322                                                                     |       | 17.80             |   | 2.97 |
|                          |       | Natural Gas(2)                                |       | 1,140                                                                   |       | 17.90             |   | 2.98 |
|                          |       | Non-Conventional Oil and Gas Activities (CBM) |       | 68                                                                      |       | 10.40             |   | 1.73 |
|                          |       | TOTAL                                         |       | 4,362                                                                   |       | 21.10             |   | 3.52 |

 

----

Notes:

 

(1)                                  Including solution gas andother by-products.

 

3

----

 

(2)                                  Including by-products butexcluding solution gas and by-products from oil wells.

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

 

**Notesto Reserves Data Tables**

** **

1.                                       Columns may not add due to rounding.

 

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

 

**Reserves Categories**

** **

Reservesare estimated remaining quantities of oil and natural gas and relatedsubstances anticipated to be recoverable from known accumulations, as of agiven 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.

 

Reservesare classified according to the degree of certainty associated with theestimates.

 

(a)                                 **Proved reserves**are thosereserves that can be estimated with a high degree of certainty to berecoverable. It is likely that the actual remaining quantities recovered willexceed the estimated proved reserves.

 

(b)                                **Probable reserves** arethose additional reserves that are less certain to be recovered than provedreserves. It is equally likely that the actual remaining quantities recoveredwill be greater or less than the sum of the estimated proved plus probablereserves.

 

Othercriteria that must also be met for the classification of reserves are providedin the COGE Handbook.

 

**Development andProduction Status**

** **

Eachof the reserves categories (proved and probable) may be divided into developedand undeveloped categories.

 

(a)                                  **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 maybe subdivided into producing 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 becurrently producing or, if shut-in, they must have previously been onproduction, and the date of resumption of production must be known withreasonable 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.

 

(b)                                 **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 of production.They must fully meet the requirements of the reserves category (proved,probable) to which they are assigned.

 

4

----

 

Inmulti-well pools, it may be appropriate to allocate total pool reserves betweenthe developed and undeveloped categories or to subdivide the developed reservesfor the pool between developed producing and developed non-producing. Thisallocation should be based on the estimator’s assessment as to the reservesthat will be recovered from specific wells, facilities and completion intervalsin the pool and their respective development 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 to the highest level sum of individual entity estimates for whichreserves estimates are presented). Reported reserves should target thefollowing levels of certainty under 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.

 

Aqualitative measure of the certainty levels pertaining to estimates preparedfor the various reserves categories is desirable to provide a clearerunderstanding of the associated risks and uncertainties. However, the majorityof reserves estimates are prepared using deterministic methods that do notprovide a mathematically derived quantitative measure of probability. In principle,there should be no difference between estimates prepared using probabilistic ordeterministic methods.

 

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

 

3.                                       **Forecast prices and costs**

** **

NI51-101 defines “forecast prices and costs” as future prices and costs that are:(i) generally acceptable as being a reasonable outlook of the future; and (ii) if,and only 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).

 

Theforecast cost and price assumptions include increases in wellhead sellingprices and take into account inflation with respect to future operating andcapital costs.  Crude oil, natural gasand natural gas liquids benchmark reference pricing, as at December 31,2007, inflation and exchange rates utilized in the Sproule Canetic Report wereas follows:

 

5

----

 

SUMMARY OF PRICING AND INFLATION RATEASSUMPTIONSas of December 31, 2007FORECAST PRICES AND COSTS

 
| ** ** | ** ** | **OIL**                               | ** ** | ** **                                            | ** ** | **EDMONTON LIQUIDS PRICES**        | ** ** | ** **                                    | ** ** | ** **                         | ** ** |
|------------|------------|---------------------------------------|------------|-------------------------------------------------------|------------|----------------------------------------------|------------|-----------------------------------------------|------------|------------------------------------|------------|
| **Year**   | ** ** | **WTI  Cushing  Oklahoma  ($US/bbl)** | ** ** | **Edmonton  Par Price  40oAPI  ($Cdn/bbl)** | ** ** | **Hardisty  Heavy  12oAPI  ($Cdn/bbl)** | ** ** | **Cromer  Medium  29.3oAPI  ($Cdn/bbl)** | ** ** | **NATURAL  GAS  AECO  ($Cdn/Mcf)** | ** ** | **Propane  ($Cdn/bbl)** | ** ** | **Butane  ($Cdn/bbl)** | ** ** | **Pentanes  Plus  ($Cdn/bbl)** | ** ** | **INFLATION  RATES(1)  %/year** | ** ** | **EXCHANGE  RATE(2)  ($US equals  $ 1 Cdn)** | ** ** |
|       |       |                                  |       |                                                  |       |                                         |       |                                          |       |                               |       |   |   |   |   |   |   |   |   |   |   |
| Forecast   |       |                                  |       |                                                  |       |                                         |       |                                          |       |                               |       |   |   |   |   |   |   |   |   |   |   |
| 2008       |       | 90.81                                 |       | 89.63                                                 |       | 54.34                                        |       | 77.54                                         |       | 6.63                               |       | 55.30 |   | 69.30 |   | 91.61 |   | — |   | 1.000 |   |
| 2009       |       | 87.00                                 |       | 85.82                                                 |       | 52.01                                        |       | 74.24                                         |       | 7.38                               |       | 52.94 |   | 66.35 |   | 87.71 |   | 2.0 |   | 1.000 |   |
| 2010       |       | 84.33                                 |       | 83.13                                                 |       | 50.38                                        |       | 71.91                                         |       | 7.65                               |       | 51.25 |   | 64.23 |   | 84.97 |   | 2.0 |   | 1.000 |   |
| 2011       |       | 82.39                                 |       | 81.18                                                 |       | 49.18                                        |       | 70.22                                         |       | 7.65                               |       | 50.05 |   | 62.72 |   | 82.97 |   | 2.0 |   | 1.000 |   |
| 2012       |       | 82.13                                 |       | 80.92                                                 |       | 49.02                                        |       | 69.99                                         |       | 7.60                               |       | 49.89 |   | 62.53 |   | 82.70 |   | 2.0 |   | 1.000 |   |
| 2013       |       | 82.40                                 |       | 81.18                                                 |       | 49.71                                        |       | 70.22                                         |       | 7.69                               |       | 50.05 |   | 62.72 |   | 82.97 |   | 2.0 |   | 1.000 |   |
| 2014       |       | 83.23                                 |       | 81.99                                                 |       | 50.74                                        |       | 70.92                                         |       | 7.88                               |       | 50.53 |   | 63.33 |   | 83.80 |   | 2.0 |   | 1.000 |   |
| 2015       |       | 84.08                                 |       | 82.82                                                 |       | 51.78                                        |       | 71.63                                         |       | 8.05                               |       | 51.02 |   | 63.95 |   | 84.66 |   | 2.0 |   | 1.000 |   |
| 2016       |       | 84.94                                 |       | 83.68                                                 |       | 52.84                                        |       | 72.37                                         |       | 8.23                               |       | 51.53 |   | 64.59 |   | 85.53 |   | 2.0 |   | 1.000 |   |
| 2017       |       | 86.65                                 |       | 85.37                                                 |       | 53.92                                        |       | 73.83                                         |       | 8.41                               |       | 52.57 |   | 65.89 |   | 87.26 |   | 2.0 |   | 1.000 |   |
| 2018       |       | 88.38                                 |       | 87.08                                                 |       | 55.00                                        |       | 75.31                                         |       | 8.58                               |       | 53.62 |   | 67.21 |   | 89.00 |   | 2.0 |   | 1.000 |   |
| Thereafter |       | +2                                    | %          | +2                                                    | %          | +2                                           | %          | +2                                            | %          | +2                                 | %          | +2 | % | +2 | % | +2 | % | 2.0 |   | 1.000 |   |

 

----

Notes:

 

(1)                                  Inflation rates forforecasting prices and costs.

(2)                                  Exchange rates used togenerate the benchmark reference prices in this table.

 

Weightedaverage actual prices realized, including hedging activities, for the yearended December 31, 2007 were $7.39/Mcf for natural gas, $65.33/bbl forlight and medium crude oil, $46.43/bbl for heavy oil and $49.34/bbl for naturalgas liquids.

 

4.                                       **Future Development Costs**

** **

Thefollowing table sets forth development costs deducted in the estimation ofCanetic’s future net revenue attributable to the reserve categories notedbelow.

 

 
| ** **                         | ** ** | **Forecast Prices and Costs** | ** ** |
|------------------------------------|------------|----------------------------------------------|------------|
| **Year**                           | ** ** | **Proved Reserves  (MM$)**              | ** ** | **Proved Plus Probable  Reserves (MM$)** | ** ** |
|                               |       |                                         |       |   |   |
| 2008                               |       | 89                                           |       | 135 |   |
| 2009                               |       | 48                                           |       | 119 |   |
| 2010                               |       | 9                                            |       | 16 |   |
| 2011                               |       | 5                                            |       | 8 |   |
| 2012                               |       | 5                                            |       | 5 |   |
| Total:  Undiscounted for all years |       | 160                                          |       | 292 |   |

 

PennWest currently expects to fund the development costs of the reserves throughinternally generated funds flow withheld from distributions.

 

6

----

 

Therecan be no guarantee that funds will be available or that we will allocatefunding to develop all of the reserves attributed in the Sproule CaneticReport.  Failure to develop thosereserves would have a negative impact on future production and funds flow andcould result in negative revisions to Canetic’s reserves.

 

Theinterest and other costs of any external funding are not included in thereserves and future net revenue estimates and would reduce reserves and futurenet revenue to some degree depending upon the funding sources utilized.  We do not currently anticipate that interestor other funding costs would make development of any property uneconomic.

 

5.                                       Estimated future well abandonment costs related to reserve wellshave been taken into account by Sproule in determining the aggregate future netrevenue therefrom.

 

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

 

7.                                       All factual data supplied to Sproule was accepted as represented. Nofield inspection was conducted.

 

8.                                       **The estimates of future net revenuepresented in the tables above do not represent fair market value.**

** **

**AdditionalInformation Relating to Reserves Data**

** **

***Undeveloped Reserves***

*** ***

Undeveloped reserves are attributed bySproule in accordance with standards and procedures contained in the COGEHandbook.  Proved undeveloped reservesare those reserves that can be estimated with a high degree of certainty andare expected to be recovered from known accumulations where a significantexpenditure is required to render them capable of production.  Probable undeveloped reserves are thosereserves that are less certain to be recovered than proved reserves and areexpected to be recovered from known accumulations where a significantexpenditure is required to render them capable of production.

 

In some cases, it will take longer than two yearsto develop these reserves.  Penn Westplans to develop approximately one-half of the proved undeveloped reserves inthe Sproule Canetic Report over the next two years and the significant majorityof the proved undeveloped reserves over the next five years.** **Thereare a number of factors that could result in delayed or cancelled development,including the following: (i) changing economic conditions (due to pricing,operating and capital expenditure fluctuations); (ii) changing technicalconditions (including production anomalies, such as water breakthrough oraccelerated depletion); (iii) multi-zone developments (for instance, aprospective formation completion may be delayed until the initial completion isno longer economic); (iv) a larger development program may need to bespread out over several years to optimize capital allocation and facilityutilization; and (v) surface access issues (including those relating toland owners, weather conditions and regulatory approvals).  For more information, see “Risk Factors”.

 

***Proved Undeveloped Reserves***

*** ***

The following table discloses, for eachproduct type, the gross volumes of proved undeveloped reserves that were firstattributed, net of conversions and revisions, in each of the most recent threefinancial years and, in the aggregate, before that time.

 
| ** **     | ** ** | **Light and Medium Oil  (Mbbl)** | ** ** | **Heavy Oil  (Mbbl)**            | ** ** | **Natural Gas  (MMcf)** | ** ** | **NGLs  (Mbbl)**                      | ** ** |
|----------------|------------|-------------------------------------------------|------------|---------------------------------------|------------|------------------------------|------------|---------------------------------------|------------|
| **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 |       | 1,293                                           |       | 1,293                                 |       | —                       |       | —                                |       | 4,060 |   | 4,060 |   | 48 |   | 48 |   |
| 2005           |       | 6,924                                           |       | 8,217                                 |       | 346                          |       | 346                                   |       | 13,694 |   | 17,754 |   | 257 |   | 304 |   |
| 2006           |       | 3,440                                           |       | 11,657                                |       | 1,181                        |       | 1,527                                 |       | 45,857 |   | 63,611 |   | 613 |   | 917 |   |
| 2007           |       | —                                          |       | 3,543                                 |       | —                       |       | 484                                   |       | — |   | 20,162 |   | — |   | 259 |   |

 

Sproule has assigned 7.7 MMboe of provenundeveloped reserves in the Sproule Canetic Report under forecast prices andcosts, together with $109.2 million of associated undiscounted future capitalexpenditures.  Proven undeveloped capital

 

7

----

 

spending in the first two forecast years ofthe Sproule Canetic Report accounts for $105.6 million, or 97 percent, of thetotal forecast.  These figures increaseto $108.4 million or 99 percent, during the first five years of the SprouleCanetic Report.

*** ***

***Probable Undeveloped Reserves***

*** ***

The following table discloses, for eachproduct type, the gross volumes of probable undeveloped reserves that werefirst attributed, net of conversions and revisions, in each of the most recentthree financial years and, in the aggregate, before that time.

 
| ** **     | ** ** | **Light and Medium Oil  (Mbbl)** | ** ** | **Heavy Oil  (Mbbl)**            | ** ** | **Natural Gas  (MMcf)** | ** ** | **NGLs  (Mbbl)**                      | ** ** |
|----------------|------------|-------------------------------------------------|------------|---------------------------------------|------------|------------------------------|------------|---------------------------------------|------------|
| **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 |       | 1,127                                           |       | 1,127                                 |       | —                       |       | —                                |       | 2,918 |   | 2,918 |   | 32 |   | 32 |   |
| 2005           |       | 3,254                                           |       | 4,381                                 |       | 96                           |       | 96                                    |       | 5,005 |   | 7,923 |   | 97 |   | 128 |   |
| 2006           |       | 476                                             |       | 4,857                                 |       | 446                          |       | 542                                   |       | 30,981 |   | 38,904 |   | 282 |   | 410 |   |
| 2007           |       | —                                          |       | 1,344                                 |       | —                       |       | 135                                   |       | — |   | 9,736 |   | — |   | 106 |   |

 

Sproule has assigned three MMboe of probableundeveloped reserves, which are primarily associated with proved undevelopedreserve assignments but have a less likely probability of being recovered thansuch associated proved undeveloped reserve assignments.

 

***Significant Factors or Uncertainties***

*** ***

The development schedule of Canetic’sundeveloped reserves is based on forecast price assumptions for thedetermination of economic projects.  Theactual prices that occur may be significantly lower or higher resulting in someprojects being delayed or accelerated, as the case may be.  See “Risk Factors – Volatility of Oil and NaturalGas Prices”.

 

Penn West does not anticipate that anysignificant economic factors or other significant uncertainties will affect anyparticular components of Canetic’s reserves data.  However, Canetic’s reserves can be affectedsignificantly by fluctuations in product pricing, capital expenditures,operating costs, royalty regimes and well performance that are beyond ourcontrol.

*** ***

***Additional Information ConcerningAbandonment and Reclamation Costs***

*** ***

Overall costs are based on well boreabandonment and reclamation costs and liability issues such as flare pitremediation, and facility decommissioning, remediation, and reclamationcosts.  These costs were estimated usingPenn West’s experience conducting annual abandonment and reclamation programsover the past several years.

 

Penn West reviews suspended or standing wellbores for reactivation, recompletion or sale and conducts systematicabandonment programs for those well bores that do not meet our criteria.  A portion of Penn West’s liability issues areretired every year and facilities are decommissioned when all the wellsproducing to them have been abandoned. All of Penn West’s liability reduction programs take into accountseasonal access, high priority and stakeholder issues, and opportunities for multi-locationprograms to reduce costs.

 

Canetic’s total inventory is estimated at5,660 net well bores and 561 facilities as of December 31, 2007.  Penn West expects to incur abandonment andreclamation costs in respect to all of these wells, facilities and otherproperties associated with these operations.

 

The total amount of abandonment andreclamation costs, net of estimated salvage values, that Penn West expects toincur, including wells that extend beyond the 50-year limit in the SprouleCanetic Report, are summarized in the following table:

 

8

----

 
| **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, 2007 |       | 777                                                                                                            |       | 87                                                                                                                            |       |
|                                          |       |                                                                                                           |       |                                                                                                                          |       |
| Anticipated  to be paid in 2008               |       | 20                                                                                                             |       | 18                                                                                                                            |       |
| Anticipated  to be paid in 2009               |       | 21                                                                                                             |       | 17                                                                                                                            |       |
| Anticipated  to be paid in 2010               |       | 22                                                                                                             |       | 17                                                                                                                            |       |

 

The above table includes certain abandonmentand reclamation costs, net of salvage values, not included in the SprouleCanetic Report and not deducted in estimating future net revenue as disclosedearlier in this Annual Information Form. Escalated at two percent and undiscounted, the costs not deducted were$347 million, and escalated at two percent and discounted at 10 percent,these costs were $39 million.

 

**OTHER OIL AND GAS INFORMATION**

 

Canetic’s portfolio of properties as at December 31,2007 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.

** **

**Principal Properties**

** **

The following is a description of Canetic’sprincipal oil and natural gas properties as at December 31, 2007.  Reserve amounts are stated at December 31, 2007, based on forecast cost and price assumptionsas evaluated in the Sproule Canetic Report prepared by Sproule.  Information in respect of gross and net acresand well counts is as at December 31, 2007, and information in respect ofproduction is for the year ended December 31, 2007 except where indicatedotherwise.  Due to the fact that Canetichas been active at acquiring additional interests in its principal properties,the working interest share and interest in gross and net acres and wells as at December 31,2007 may not directly correspond to the stated production for the year, whichonly includes production since the date the interests were acquired byCanetic.  The estimates of reserves andfuture net revenue for individual properties may not reflect the sameconfidence level as estimates of reserves and future net revenue for allproperties, due to the application of statistical methods of aggregatingindividual properties.

 

All of the properties described below are located in Canada and, specifically, in the provinces of Alberta,British Columbia, Saskatchewan and Manitoba. Canetic has minor interests in the United States.

 

The properties represent 100 percent of thetotal net proved plus probable reserves as assigned by Sproule in the Sproule Canetic Report.** **Thereare no material properties to which reserves have been attributed which arecapable of producing but which are not producing.

** **

**Major Operating Regions**

** **

The following table shows Canetic’s reported average daily production and proved plusprobable reserves, as at December 31, 2007, by major core region:

 

9

----

 
| ** **                           | ** ** | **Average Daily Production**     | ** ** | **Proved Plus Probable Gross Reserves** | ** ** | ** **         | ** ** |
|--------------------------------------|------------|--------------------------------------------|------------|-------------------------------------------------------------|------------|--------------------|------------|
| ** **                           | ** ** | **Crude Oil  and NGLs  (bbl/d)** | ** ** | **Natural Gas  (MMcf/d)**                              | ** ** | **Total  (boe/d)** | ** ** | **Crude Oil  and NGLs  (MMbbl)** | ** ** | **Natural Gas  (Bcf)** | ** ** | **Total  (MMboe)** | ** ** | **Undeveloped  Land  (000 net acres)** | ** ** |
|                                 |       |                                       |       |                                                        |       |               |       |   |   |   |   |   |   |   |   |
| Central                              |       | 7,497                                      |       | 48.0                                                        |       | 15,490             |       | 20.7 |   | 126.5 |   | 41.8 |   | 111 |   |
| Northern                             |       | 3,697                                      |       | 44.9                                                        |       | 11,176             |       | 19.8 |   | 181.2 |   | 50.0 |   | 245 |   |
| Rocky                                |       | 5,000                                      |       | 67.3                                                        |       | 16,224             |       | 19.7 |   | 173.3 |   | 48.6 |   | 127 |   |
| Southern                             |       | 12,593                                     |       | 25.9                                                        |       | 16,905             |       | 42.6 |   | 85.6 |   | 56.9 |   | 179 |   |
| Williston Basin                      |       | 11,581                                     |       | 8.2                                                         |       | 12,945             |       | 43.7 |   | 31.3 |   | 49.0 |   | 112 |   |
| Total                                |       | 40,368                                     |       | 194.3                                                       |       | 72,740             |       | 146.5 |   | 597.9 |   | 246.3 |   | 774 |   |
| % of daily production/total reserves |       | 56                                         | %          | 44                                                          | %          | 100                | %          | 60 | % | 40 | % | 100 | % |   |   |

** **

**Oil and Natural Gas Properties**

*** ***

Canetic’s production andreserves are attributed to more than 250 producing properties.  No single property accounts for more than10 percent of Canetic’s reserves.  Ageneral discussion of Canetic’s operations and activities in each of Canetic’score areas follows.

 

***Williston Basin District***

*** ***

The Williston Basin district provides Caneticwith 17 percent of its total production. Located primarily in southeastSaskatchewan, with minor properties in Manitoba, North Dakota, Montana andWyoming, this area continues to be an active area providing high netback lightoil from legacy assets.  A total of 55(29.9 net) wells were drilled in 2007, including 37 (16.5 net) oil wells and 16(13.3 net) CBM wells. Plans are to drill 17 wells in this area in 2008targeting high netback, light oil.

 

*GreaterQueensdale, Saskatchewan*

* *

The Greater Queensdale assets are located insoutheast Saskatchewan about 100-150 kilometres north and east of Estevan.  This area includes the Ingoldsby, Queensdale,Gainsborough, Cantal and Edenvale properties.

 

The main producing assets of this areainclude portions of the Queensdale Frobisher-Alida Pool, Alida WestFrobisher-Alida Pool (Edenvale), Cantal Frobisher-Alida Pool, Nottingham SouthFrobisher-Alida Pool, and the Ingoldsby Frobisher Alida Pool.  The light oil (30-38°API) is produced fromthe Frobisher-Alida beds at 1,000 to 1,400 metres in depth.  Substantially all of the production in whichCanetic has an interest is pipelined to company owned central facilitiesincluding oil, gas and water separation and treating equipment, crude oilpipeline connection, and salt water disposal facilities.  Canetic has a working interest in theNAL-operated Nottingham gas plant at 8-17-5-32 W1M and associated gas-gatheringsystem where the majority of the area’s conserved solution gas is processed.

 

In 2007, Canetic drilled a successful seven(six net) horizontal well program focusing on the highly deliverable Alidaformation on these legacy assets.  Plansare in place for a six well operated program in 2008.

 

*North Dakotaand Montana, USA*

* *

The properties located in eastern Montana andsouthwest North Dakota, USA are about 200 to 300 kilometres south ofEstevan.  Canetic has working interestsranging from 19 percent to 100 percent.

 

The main producing assets in this areainclude portions of the Brush Mountain Ratcliffe Pool, Tracy Mountain TylerPool and Davis Creek Madison Pool.  Thelight oil (35-42° API) is produced from the Mississippian Madison andPennsylvanian Tyler beds at 2,500 to 3,000 metres in depth.

 

Substantially all of the production in whichCanetic has an interest is produced to single well batteries where oil, waterand gas are separated; gas is consumed as well site fuel or flared.  Oil and water are trucked for sale anddisposal respectively.

 

10

----

 

*Wyoming, USA –Powder River Basin Coalbed Methane*

* *

The Wyoming properties are located in thePowder River Basin, north of Casper.  Theproperties are comprised of 11,298 net acres of undeveloped land with anaverage working interest of 50%.  During2007, 16 (13.3 net) development Coalbed Methane (“**CBM**”) wells were drilled on these properties.  Assets at Big Bend, North Carson, Coal Gulch,and Kane target the Big George, Anderson, Canyon/Cook, Wall/Pawnee and Wyodakcoals at depths ranging from 100 to 700 metres.

 

***Southern District***

*** ***

The Southern District includes propertieslocated in southern and eastern Alberta and in western to southwesternSaskatchewan.  Assets vary throughoutthis district ranging from medium to light crude oil in southern Alberta andsouthwest Saskatchewan to heavy oil properties in the Lloydminster area.  The area provides Canetic with 24 percent ofits production and continues to be an active area for growth.  Highlights of the Southern District includelight oil development on royalty free lands in southern Alberta and a royaltyholiday on horizontal drilling in the Leitchville area of southwestSaskatchewan.  Canetic exited the yearproducing 18,000 boe/d in the Southern District.  A total of 58 (37.4 net) wells were drilledin 2007, including 43 (35.2 net) oil wells and 14 (1.2 net) gas wells.  One well was drilled and abandoned.

 

*Countess,Alberta*

* *

The Countess properties are located insouthern Alberta, approximately 130 kilometres southeast of Calgary.  The properties in this area have a workinginterest between 50 and 100 percent for the oil assets and 17.5 to 100 percentfor the gas assets.

 

These assets are comprised of Mannville oiland shallow Medicine Hat/Milk River gas. The gas wells are drilled at an average depth of 550 metres.  Canetic gas handling facilities at Countessare comprised of a compressor and processing facility and several boostercompressors.  The compression facilitiesboost the gas to sales pipeline operating pressures.

 

The majority of the Countess oil productionis obtained from the Rosemary Lower Mannville Z and RR oil pools and theDuchess Lower Mannville X and VVV oil pools, which are currently under activewaterflood schemes.  The medium oil(26-33° API) is produced from Lower Mannville sandstones at 1,100 to 1,200 metresin depth.

 

Substantially all of the Countess oilproduction is pipelined to one of two 100 percent working interest centralfacilities located at Rosemary and Duchess. The central facilities include oil, gas and water separation andtreating equipment, a crude oil pipeline connection, salt water disposalfacilities, and solution gas gathering facilities.  A small portion of the production is producedto single well batteries where oil and water are separated and trucked tovarious area facilities for processing and sale.

 

*Leitchville,Southwest Saskatchewan*

* *

Located near Shaunavon, Saskatchewanapproximately 450 kilometres southeast of Calgary, this area became a veryactive area for Canetic in 2007.  Theemergence of the Lower Shaunavon play, unlocked by multi-stage horizontalfracture stimulation technology, triggered a flood of activity by Canetic whichincluded the drilling of 10 (nine net) wells and actively acquiring undevelopedacreage in 2007.  The Lower Shaunavon isfound at a depth of roughly 1,400 metres. Horizontal sections average between 1,000 and 1,200 metres inlength.  The medium quality (23 degreeAPI) crude is produced into single well batteries.  Plans are in place to initiate facilitydevelopment to limit the proliferation of single well batteries.  For 2008, Penn West plans to continue toacquire land and have an active drilling program.  A minimum of 18 wells are slated to be spudthroughout the year.

 

*Furness,Saskatchewan*

* *

The greater Furness area is located inwestern Saskatchewan in Townships 48 and 49, Ranges 26 through 28 W3M.  Furness was acquired late in 2003 by Caneticpursuant to the acquisition of Exodus Energy Ltd. and is primarily a heavy oilfield.  The primary producing zone of interestis the Sparky Sand, with additional production provided from the McLaren andGeneral Petroleum Formations.

 

11

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Canetic has a 75 percent working interest ina central oil battery that is connected to a sales oil pipeline.  The battery is located at 14-08-048-27W3M andis capable of handling 1,600 bbl/d of oil.

 

In 2007, a successful seven well heavy oilprogram was drilled in the area which has led to additional follow upopportunities.  In 2008, Penn West plansto drill between 14 and 20 wells in the Furness area targeting theseopportunities.

 

***Central District***

*** ***

The Central district includes propertieslocated in western and west-central Alberta. Major assets are found inproperties located in Pembina, Corbett, Bigoray and Acheson.  Production for the area exited the year at15,109 boe/d and accounted for roughly 20 percent of Canetic’s overallproduction.  The area is characterized bylight oil and liquids-rich gas.  CBMdevelopment potential on 100 percent working interest lands in the Corbett areaalso lies in this district.  In 2007, atotal of 52 (20.6 net) wells were drilled in the Central district including 26(10.8 net) oil wells and 20 (8.7 net) gas wells.  Six (one net) service wells were drilled fordisposal purposes.

 

*Acheson,Alberta*

* *

The Acheson area is west of Edmonton andincludes interests in the Acheson D-3a Unit, the Acheson Lower Cretaceous Unit No. 1,the Acheson North D-2 Pool Unit and non-unit production.  Canetic’s overall working interest in thearea is 99.7 percent.

 

Gas is processed at the 100 percent workinginterest operated 5-2-53-26W4M Acheson gas plant, capable of processing 24MMcf/d of gas.  The oil from the 100percent owned Acheson field is processed at the unit battery and fluid handlingfacility located at the 5-2-53-26W4 site.

* *

Acheson is a multi-zone area with productioncoming from the Leduc, Nisku, Detrital, Basal Quartz and Viking zones.  The Leduc Formation is characterized by thedevelopment of numerous isolated reef complexes and a broad carbonate shelf,all of which developed on the Cooking Lake platform and is responsible for themajority of Acheson’s current production. The D-3a Pool started blow down in June 2003 by the controlledproduction of reservoir and injected hydrocarbons following the termination ofan enhanced recovery scheme to increase the recovery of original oil reserves.

 

In 2007, this property continued to be anactive part of Canetic’s budget with aggressive optimization projects targetingup-hole oil and gas recompletions, as well as an 11 (8.8 net) well programtargeting light oil in the Detrital formation. In 2008, a seven to 13 well drilling program is scheduled for early inthe year.

 

*Corbett Creek,Alberta*

* *

The Corbett Creek area is locatedapproximately 125 kilometres northwest of the city of Edmonton.  Working interests vary from 40 to 100 percentin the Mannville CBM play that has developed in the area over the past fewyears.  Canetic has both operated andnon-operated interests in this play and participated with one joint venturepartner in 2007 in the drilling of nine wells (3.7 net).  Production is obtained by drilling single tomulti-leg horizontals targeting a two to three-metre thick coal atapproximately 975 metres total vertical depth. Horizontal legs can be over 1,500 metres in length.

 

***Rocky District***

*** ***

The Rocky district includes propertieslocated in west central Alberta. Production exited 2007 at over 16,000 boe/d, which accounts for roughly21 percent of Canetic’s overall production. The area is characterized by light oil properties in Willesden Green,Gilby and Innisfail, and by large gas reservoirs in the Hoadley/Ferrybankarea.  In total, 37 (17 net) wells weredrilled on these properties during 2007, including nine (1.8 net) oil wells and28 (15.1 net) gas wells.

 

*WillesdenGreen, Alberta*

* *

The Willesden Green area is locatedapproximately 125 kilometres southwest of Edmonton.  The properties include unit and non-unitinterests, with the majority of the production operated and with high workinginterests.  The unit interests consist offour producing oil units, with two large operated units and one wholly ownedproject area producing light oil (41° API) from

 

12

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the Cardium formation.  Two other units (one operated) produce long-lifelight crude oil and natural gas from the Viking formation.  The properties have opportunities for infilldrilling on 160-acre spacing units, opportunities to enhance water floodperformance, and several stimulation candidates.  The non-unit interests produce light gravitycrude oil from the Cardium formation and Mannville groups, and natural gas fromthe Scollard, Belly River, Cardium, Ellerslie, Ostracod, Rock Creek and Nordeggformations.  This is a multi-target areawith shallow to moderate drill depths and a large concentrated land positionwith the majority of the lands operated. There are also deeper Mannville drilling targets defined by seismicdata, as well as many prospects in the shallower Belly River, Edmonton,Paskapoo and Scollard formations. Canetic owns the facilities associated with the production, as well as a21.7 percent interest in the Imperial Oil Ltd. Willesden Green natural gasplant.  Canetic also owns a 20 MMcf/d gasprocessing facility, with pipeline infrastructure that allows Canetic toprocess the majority of our production in this area in our owned gasplant.  This plant was constructed inlate 2006 and early 2007, and was commissioned in February 2007.

 

In 2007, Canetic participated in a successful11 (eight net) well drilling program in the area targeting natural gas inmulti-zone horizons.

 

*Hoadley/Ferrybank,Alberta*

* *

The Hoadley — Ferrybank area is located 90kilometres southwest of Edmonton.  Thisproperty was purchased by Canetic in 2006 through the acquisition of interestsin oil and natural gas reserves and associated facilities located in Albertaand British Columbia.  Production isentirely natural gas and associated liquids primarily from the Hoadley BarrierBar complex in the Glauconite formation. Other producing horizons include the Edmonton Sand, the Ellerslie, andColony.  This property includes 204,000net developed and undeveloped acres with an average working interest ofapproximately 67 percent, with 90 percent of the production operated byCanetic.  Canetic operates 37 compressorsin the area and has ownership in nine others. Gas is processed primarily through the Rimbey plant operated by KeyeraEnergy Ltd.  Canetic has a 41 percentownership in the Encana Oil and Gas Partnership operated Ferrybank plant at2-1-44-28 W4 that has a capacity of 35 mmcf/d. Canetic has a 13.24 percent ownership in the Mikwan Plant operated byVermillion Resources Ltd. that has a capacity of 9.5 mmcf/d.

 

In 2007, Canetic drilled a successful five(4.5 net) well program targeting glauconite gas.  In 2008, a six-well program is scheduled.

 

***Northern District***

*** ***

The Northern district includes propertieslocated in northwest Alberta and northeast British Columbia.  Exit volumes in 2007 totalled 12,500 boe/d ofproduction, representing approximately 17 percent of Canetic’s totalproduction.  This district is characterizedby liquids-rich gas in the Pouce Coupe, Clarke Lake, Fort St. John and Buickprospect areas, and light oil properties in Pouce and Mitsue.  In total 30 (6.61 net) wells were drilled onthese properties during 2007, including 10 (0.53 net) oil wells and 16 (4.72net) gas wells.  Four (1.36 net) wellswere dry and abandoned.

 

*PouceCoupe, Alberta*

* *

The Pouce Coupe properties are locatedapproximately 80 kilometres northwest of Grande Prairie.  Canetic operates the Pouce Coupe SouthBoundary ‘B’ Unit No. 2 with a 62.8 percent working interest.  This high netback, light oil unit includes anoil battery and water injection facility, as well as amine, refrigeration andgas compression facilities.  Productionwithin the unit is obtained from the Boundary Lake member of the Charlie Lakeformation.  Canetic also holds a 20.793percent working interest in the Pouce Coupe South Boundary B Unit operated byEnerplus Resources Corporation.  Non-unitproduction consists of wells with interests ranging from a gross overridingroyalty to a 78.75 percent working interest. Producing formations primarily include the Doig, Bluesky, Gething,Baldonnel, Halfway and Boundary Lake.

 

*Fort St. John,British Columbia*

* *

The Fort St. John properties are primarilylocated in the Fort St. John area in northeast British Columbia.  The principal properties are within a 20kilometre radius of Fort St. John. Canetic has an average working interest of 55 percent.  Canetic also has 50 percent and 65 percentworking interests, respectively, in two operated compressor stations and 38.44percent and 27 percent working interests, respectively, in a further twonon-operated compressor stations.  In September of2006, Canetic

 

13

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obtained additional production in this areathrough the Samson Acquisition.  Workinginterests average 57 percent in this new acreage and Canetic operates 79percent of its production.  Major fieldsinclude Stoddart, Monias, Airport, and Wilder. Producing horizons include Halfway, Doig, and Belloy.  Canetic obtained operatorship in 10compressors through this transaction and has additional ownership in 7more.  All gas is processed through DukeMidstream.

 

*Fireweed/BuickCreek, British Columbia*

* *

The Fireweed/Buick Creek properties arelocated approximately 75 kilometres north and northwest of Fort St. John innortheast British Columbia.  Caneticobtained a large land position through the Samson Acquisition in September of2006.  Canetic has an average workinginterest of 57 percent in the new properties and operates 91 percent of itsproduction.  The majority of productioncomes from the Dunlevy Sand with minor production from the Doig, Halfway,Bluesky, and Baldonnel horizons.  Caneticoperates nine compressors in the area and has additional ownership in fiveothers.  All gas is processed throughDuke Midstream.

 

*Clarke Lake*

* *

The Clarke Lake properties arelocated approximately 50 kilometres south and east of Fort Nelson in northeastBritish Columbia.  Canetic has a small100 percent working interest land position adjacent to theClarke Lake Slave Point pool.  In 2007,Canetic drilled three (three net) wells targeting the Slave Point formationwith a 66.7 percent success rate. Production was tied in to Canetic’s facility.

 

***AdditionalInformation***

*** ***

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

 

For a discussion of properties to whichreserves have been attributed and which are capable of producing but which arenot producing, see “Additional Information Relating to Reserves Data –Undeveloped Reserves” above.

 

**Oil AndGas Wells**

** **

The following table sets forth the number andstatus of wells in which Canetic had a working interest as at December 31,2007.

 
| ** **        | ** ** | **Producing** | ** ** | **Non-Producing** | ** ** | **Total**  | ** ** |
|-------------------|------------|---------------|------------|-------------------|------------|------------|------------|
| ** **        | ** ** | **Oil**       | ** ** | **Gas**           | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **        | ** ** | **Gross**     | ** ** | **Net**           | ** ** | **Gross**  | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
|              |       |          |       |              |       |       |       |   |   |   |   |   |   |   |   |   |   |
| Alberta           |       | 3,154         |       | 1,170             |       | 2,103      |       | 1,164 |   | 1,718 |   | 587 |   | 6,975 |   | 2,921 |   |
| British  Columbia |       | 69            |       | 25                |       | 273        |       | 150 |   | 77 |   | 24 |   | 419 |   | 199 |   |
| Saskatchewan      |       | 3,151         |       | 1,846             |       | 332        |       | 58 |   | 875 |   | 245 |   | 4,358 |   | 2,149 |   |
| Manitoba          |       | 544           |       | 192               |       | —     |       | — |   | 162 |   | 57 |   | 706 |   | 249 |   |
| United  States    |       | 26            |       | 12                |       | 230        |       | 89 |   | 87 |   | 41 |   | 343 |   | 142 |   |
| Total             |       | 6,944         |       | 3,245             |       | 2,938      |       | 1,461 |   | 2,919 |   | 954 |   | 12,801 |   | 5,660 |   |

** **

**Propertieswith no Attributed Reserves**

** **

The following table sets out the unprovedproperties in which Canetic had an interest as at December 31, 2007.

 

14

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| ** **        | ** ** | **Unproved Properties  (000s of Acres)** | ** ** |
|-------------------|------------|---------------------------------------------------------|------------|
| ** **        | ** ** | **Gross**                                               | ** ** | **Net** | ** ** |
|              |       |                                                    |       |   |   |
| Alberta           |       | 658                                                     |       | 398 |   |
| British  Columbia |       | 214                                                     |       | 127 |   |
| Saskatchewan      |       | 194                                                     |       | 142 |   |
| Manitoba          |       | 7                                                       |       | 3 |   |
| Wyoming           |       | 22                                                      |       | 1 |   |
| Montana           |       | 2                                                       |       | 1 |   |
| North Dakota      |       | 27                                                      |       | 23 |   |
| Total             |       | 1,124                                                   |       | 695 |   |

 

We currently have no material workcommitments on these lands. The primary lease or extension term on 169,406 netacres of unproved property will expire by December 31, 2008. The right toexplore, develop and exploit these leases will be surrendered unless we qualifythem for continuation based on existing production, drilling or technicalmapping.

 

**CapitalExpenditures**

** **

The following table summarizes capitalexpenditures (net of incentives and net of certain proceeds) related to Canetic’sactivities for the year ended December 31, 2007.

 
| ** **             | ** ** | **2007  MM$** | ** ** |
|------------------------|------------|---------------|------------|
|                   |       |          |       |
| Property  Acquisitions |       |          |       |
| Proved  Properties     |       | $             | 81.6       |   |
| Unproved  Properties   |       | 31.3          |       |
| Exploration  Costs(1)  |       | 2.4           |       |
| Development  Costs(2)  |       | 417.7         |       |
| Corporate  Costs       |       | 8.1           |       |
| Capital  Expenditures  |       | $             | 541.1      |   |

 

----

Notes:

 
| (1) | Costs of  land acquired, geological and geophysical capital expenditures and drilling  costs for 2007 exploration wells drilled. |
|-----|----------------------------------------------------------------------------------------------------------------------------------|
| (2) | Includes  equipping and facilities capital expenditures.                                                                         |

 

**Explorationand Development Activities**

** **

The following table sets forth the gross andnet exploratory and development wells that Canetic participated in during theyear ended December 31, 2007.

 
| ** **  | ** ** | **Exploratory Wells** | ** ** | **Development Wells** | ** ** |
|-------------|------------|----------------------------|------------|----------------------------|------------|
| ** **  | ** ** | **Gross**                  | ** ** | **Net**                    | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Oil         |       | 3                          |       | 2                          |       | 122 |   | 63 |   |
| Natural Gas |       | 11                         |       | 6                          |       | 87 |   | 38 |   |
| Service     |       | —                     |       | —                     |       | 8 |   | 1 |   |
| Dry         |       | —                     |       | —                     |       | 5 |   | 2 |   |
| Total       |       | 14                         |       | 8                          |       | 222 |   | 104 |   |

** **

**ProductionEstimates**

** **

The following table sets out the volume ofour production estimated for the year ended December 31, 2008 which isreflected in the estimates of gross proved reserves and gross probable reservesdisclosed in the tables contained under “Disclosure of Reserves Data” above.

 

15

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| ** **                      | ** ** | **Light and  Medium Oil** | ** ** | **Heavy Oil** | ** ** | **Natural Gas** | ** ** | **Natural Gas  Liquids** | ** ** | **Total**   | ** ** |
|---------------------------------|------------|-------------------------------------|------------|--------------------|------------|----------------------|------------|--------------------------|------------|-------------|------------|
| ** **                      | ** ** | **(bbl/d)**                         | ** ** | **(bbl/d)**        | ** ** | **(Mcf/d)**          | ** ** | **(bbl/d)**              | ** ** | **(Boe/d)** | ** ** |
| ** **                      | ** ** | **Gross**                           | ** ** | **Gross**          | ** ** | **Gross**            | ** ** | **Gross**                | ** ** | **Gross**   | ** ** |
| Proved  Producing               |       | 26,683                              |       | 4,988              |       | 172,236              |       | 5,128                    |       | 65,503      |       |
| Proved  Developed Non-Producing |       | 153                                 |       | 85                 |       | 6,456                |       | 94                       |       | 1,410       |       |
| Proved  Undeveloped             |       | 810                                 |       | 111                |       | 3,055                |       | 41                       |       | 1,473       |       |
| Total Proved                    |       | 27,646                              |       | 5,184              |       | 181,747              |       | 5,263                    |       | 68,386      |       |
| Total  Probable                 |       | 1,615                               |       | 224                |       | 9,635                |       | 253                      |       | 3,719       |       |
| Total Proved  Plus Probable     |       | 29,261                              |       | 5,408              |       | 191,382              |       | 5,516                    |       | 72,105      |       |

 

No property accounts for more thannine percent of the estimated production disclosed above. For moreinformation, see “Other Oil and Gas Information – Principal Properties”.

 

**ProductionHistory**

** **

The following tables summarize certaininformation in respect of Canetic’s production, product prices received,royalties paid, production costs and resulting netback for the periodsindicated below:

 
| ** **                              | ** ** | **Quarter Ended 2007** | ** ** | **Year Ended** | ** ** |
|-----------------------------------------|------------|----------------------------------|------------|---------------------|------------|
| ** **                              | ** ** | **Mar. 31**                 | ** ** | **June 30**    | ** ** | **Sept. 30** | ** ** | **Dec. 31** | ** ** | **Dec. 31, 2007** | ** ** |
| Average  Daily Production(1)            |       |                             |       |                |       |   |   |   |   |   |   |
| Light and  Medium Crude Oil (bbl/d)     |       | 28,843                           |       | 27,989              |       | 26,349 |   | 29,869 |   | 28,260 |   |
| Heavy Oil  (bbl/d)                      |       | 7,578                            |       | 7,939               |       | 8,229 |   | 4,467 |   | 7,048 |   |
| Gas (MMcf/d)                            |       | 220.1                            |       | 211.0               |       | 205.7 |   | 182.0 |   | 204.6 |   |
| NGLs (bbl/d)                            |       | 6,916                            |       | 6,664               |       | 5,711 |   | 6,082 |   | 6,339 |   |
| Combined  (boe/d)                       |       | 80,027                           |       | 77,765              |       | 74,572 |   | 70,755 |   | 75,751 |   |
|                                    |       |                             |       |                |       |   |   |   |   |   |   |
| Average Net  Production Prices Received |       |                             |       |                |       |   |   |   |   |   |   |
| Light and  Medium Crude Oil ($/bbl)     |       | 60.82                            |       | 64.36               |       | 75.02 |   | 75.63 |   | 68.92 |   |
| Heavy Oil  ($/bbl)                      |       | 43.93                            |       | 44.00               |       | 48.63 |   | 50.96 |   | 46.43 |   |
| Gas ($/Mcf)                             |       | 7.65                             |       | 7.72                |       | 5.33 |   | 6.40 |   | 6.81 |   |
| NGLs ($/bbl)                            |       | 43.12                            |       | 46.85               |       | 50.60 |   | 57.95 |   | 49.34 |   |
| Combined  ($/boe)                       |       | 50.85                            |       | 52.62               |       | 50.45 |   | 56.59 |   | 52.55 |   |
|                                    |       |                             |       |                |       |   |   |   |   |   |   |
| Royalties  Paid                         |       |                             |       |                |       |   |   |   |   |   |   |
| Light and  Medium Crude Oil ($/bbl)     |       | 9.89                             |       | 9.86                |       | 13.11 |   | 13.44 |   | 11.57 |   |
| Heavy Oil  ($/bbl)                      |       | 5.77                             |       | 5.66                |       | 7.06 |   | 7.86 |   | 6.45 |   |
| Gas ($/Mcf)                             |       | 1.55                             |       | 1.71                |       | 0.87 |   | 1.00 |   | 1.30 |   |
| NGLs ($/bbl)                            |       | 10.33                            |       | 9.14                |       | 13.34 |   | 21.18 |   | 13.29 |   |
| Combined  ($/boe)                       |       | 9.27                             |       | 9.54                |       | 8.82 |   | 10.57 |   | 9.53 |   |
|                                    |       |                             |       |                |       |   |   |   |   |   |   |
| Production  Costs (2)(3)                |       |                             |       |                |       |   |   |   |   |   |   |
| Light and  Medium Crude Oil ($/bbl)     |       | 11.91                            |       | 13.64               |       | 15.12 |   | 16.85 |   | 14.39 |   |
| Heavy Oil  ($/bbl)                      |       | 15.72                            |       | 10.74               |       | 12.98 |   | 15.18 |   | 14.43 |   |
| Gas ($/Mcf)                             |       | 1.37                             |       | 1.58                |       | 1.34 |   | 1.99 |   | 1.56 |   |
| NGLs ($/bbl)                            |       | —                           |       | —              |       | — |   | — |   | — |   |
| Combined  ($/boe)                       |       | 9.55                             |       | 10.29               |       | 10.48 |   | 13.19 |   | 10.83 |   |
|                                    |       |                             |       |                |       |   |   |   |   |   |   |
| Transportation                          |       |                             |       |                |       |   |   |   |   |   |   |
| Light and  Medium Crude Oil ($/bbl)     |       | 0.39                             |       | 0.24                |       | 0.31 |   | 0.27 |   | 0.30 |   |
| Heavy Oil  ($/bbl)                      |       | 0.36                             |       | 0.21                |       | 0.29 |   | 0.31 |   | 0.29 |   |
| Gas ($/Mcf)                             |       | 0.29                             |       | 0.20                |       | 0.25 |   | 0.27 |   | 0.25 |   |
| NGLs ($/bbl)                            |       | 0.34                             |       | 0.24                |       | 0.28 |   | 0.30 |   | 0.29 |   |
| Combined  ($/boe)                       |       | 0.99                             |       | 0.67                |       | 0.86 |   | 0.86 |   | 0.85 |   |

 

16

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| ** **                                | ** ** | **Quarter Ended 2007** | ** ** | **Year Ended** | ** ** |
|-------------------------------------------|------------|----------------------------------|------------|---------------------|------------|
| ** **                                | ** ** | **Mar. 31**                 | ** ** | **June 30**    | ** ** | **Sept. 30** | ** ** | **Dec. 31** | ** ** | **Dec. 31, 2007** | ** ** |
| (Gain)/Loss  on Risk Management Contracts |       |                             |       |                |       |   |   |   |   |   |   |
| Light and  Medium Crude Oil ($/bbl)       |       | 0.28                             |       | 1.53                |       | 3.96 |   | 8.78 |   | 3.59 |   |
| Heavy Oil  ($/bbl)                        |       | —                           |       | —              |       | — |   | — |   | — |   |
| Gas ($/Mcf)                               |       | (0.23                            | )          | (0.29               | )          | (1.31 | ) | (0.51 | ) | (0.58 | ) |
| NGLs ($/bbl)                              |       | —                           |       | —              |       | — |   | — |   | — |   |
| Combined  ($/boe)                         |       | (0.52                            | )          | (0.08               | )          | (1.77 | ) | 2.96 |   | 0.10 |   |
|                                      |       |                             |       |                |       |   |   |   |   |   |   |
| Netback  Received(4)                      |       |                             |       |                |       |   |   |   |   |   |   |
| Light and  Medium Crude Oil ($/bbl)       |       | 38.35                            |       | 39.09               |       | 42.52 |   | 36.29 |   | 39.07 |   |
| Heavy Oil  ($/bbl)                        |       | 22.08                            |       | 27.39               |       | 28.30 |   | 27.61 |   | 26.26 |   |
| Gas ($/Mcf)                               |       | 4.67                             |       | 4.52                |       | 4.18 |   | 3.65 |   | 4.28 |   |
| NGLs ($/bbl)                              |       | 32.45                            |       | 37.47               |       | 36.98 |   | 36.47 |   | 35.76 |   |
| Combined  ($/boe)                         |       | 31.56                            |       | 32.20               |       | 32.06 |   | 29.01 |   | 31.24 |   |

 

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Notes:

 

(1)                                  Before deduction of royalties.

(2)                                  Operating expenses arecomposed of direct costs incurred to operate both oil and gas wells. A numberof assumptions are required to allocate these costs between oil, natural gasand natural gas liquids production.

(3)                                  Operating recoveriesassociated with operated properties are charged to operating costs andaccounted for as a reduction to general and administrative costs.

(4)                                  Netbacks are calculated bysubtracting royalties, operating costs, transportation and losses/gains oncommodity and foreign exchange contracts from revenues.

 

**Marketing and Future Commitments**

** **

***Natural GasMarketing***

*** ***

In 2007, Canetic received an average pricefrom the sale of natural gas, including hedging gains, of $7.39/Mcfcompared to $7.62/Mcf realized in 2006.

 

***Oil and LiquidsMarketing***

*** ***

The average quality of Canetic’scrude oil production is 31(o) API. Approximately 68 percent of Canetic’s liquids production can be attributed to light and mediumoil, with an average API of 35(o). Conventional heavy oil, at 17(o) averageAPI, comprises approximately 17 percent of total liquids production. Productionof NGLs accounts for approximately 15 percent of total liquids production.

 

The following table summarizesthe net product price received for Canetic’s production of conventional lightand medium oil and conventional heavy oil for the periods indicated:

 
| ** **             | ** ** | **2007**                            | ** ** | **2006**           | ** ** |
|------------------------|------------|-------------------------------------|------------|--------------------|------------|
| ** **             | ** ** | **Light and  Medium Oil** | ** ** | **Heavy Oil** | ** ** | **Light and  Medium Oil** | ** ** | **Heavy Oil** | ** ** |
| **Quarter ended** | ** ** | **($/bbl)**                         | ** ** | **($/bbl)**        | ** ** | **($ /bbl)** | ** ** | **($ /bbl)** | ** ** |
|                   |       |                                |       |               |       |   |   |   |   |
| March 31          |       | 60.82                               |       | 43.93              |       | 58.01 |   | 33.26 |   |
| June 30           |       | 64.36                               |       | 44.00              |       | 70.07 |   | 50.36 |   |
| September 30      |       | 75.02                               |       | 48.63              |       | 70.17 |   | 50.54 |   |
| December 31       |       | 75.63                               |       | 50.96              |       | 55.08 |   | 39.76 |   |

*** ***

***Forward Contracts***

*** ***

As at December 31, 2007, Canetic was notbound by any agreement (including a transportation agreement), directly orthrough an aggregator, under which it may be precluded from fully realizing, ormay be protected from the full effect of,

 

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future market prices for oil or natural gas,except for the following financial hedging positions that were outstanding asat December 31, 2007:

 
| ** **       | ** ** | **Notional Volume** | ** ** | **Remaining Term** | ** ** | **Pricing**         | ** ** | **Market Value(1)  (MM$ )** | ** ** |
|------------------|------------|--------------------------|------------|-------------------------|------------|---------------------|------------|---------------------------------------|------------|
| **Crude  Oil**   |       |                     |       |                    |       |                |       |                                  |       |
| WTI Collars      |       | 12,000 bbl/d             |       | Jan/08-Dec/08           |       | US$64.17-$81.49/bbl |       | (57.4                                 | )          |
| WTI Swaps        |       | 750 bbl/d                |       | Jan/08-Dec/08           |       | US$71.73/bbl        |       | (5.7                                  | )          |
|             |       |                     |       |                    |       |                |       |                                  |       |
| **Natural  Gas** |       |                     |       |                    |       |                |       |                                  |       |
| AECO Collars     |       | 90,000 GJ/d              |       | Jan/08-Mar/08           |       | $7.00 -  $11.23/GJ  |       | 6.2                                   |       |
| AECO Swaps       |       | 70,000 GJ/d              |       | Apr/08-Oct/08           |       | $6.41/GJ            |       | (0.5                                  | )          |
|             |       |                     |       |                    |       |                |       | (57.4                                 | )          |

 

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Note:

 

(1)                                  Unrealized gain (loss) basedon calculations using posted rates for similar contracts on December 31,2007.

 

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**APPENDIX C**

 

**MANDATE OF THE AUDIT COMMITTEE**

 

**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 objectives of the Committee, with respect toCompany and the Trust (hereinafter collectively 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 its responsibilitiesregarding the oversight of the Company’s compliance with legal and regulatoryrequirements.

 

**Mandate and Responsibilities of 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,material business risks are identified, monitored and mitigated where it isdetermined cost effective to do so;

 

·                                          internalcontrols over financial reporting are sufficient to meet the requirements underMI 52-109 and the United States Securities Exchange Act of 1934, asamended, and

 

·                                          legal, ethicaland regulatory 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 shouldinclude but not be limited to:

 

·                                          reviewingchanges in accounting principles, or in their application, which may have amaterial impact on the current or future years’ financial statements;

 

·                                          reviewingsignificant accruals, reserves or other estimates such as the ceiling testcalculation;

 

·                                          reviewingaccounting treatment of unusual or non-recurring transactions;

 

·                                          reviewing theTrust’s status as a “mutual fund trust” under the *Income Tax Act* (Canada);

 

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·                                          ascertainingcompliance with covenants under loan agreements and Trust Indenture;

 

·                                          reviewingadequacy of the asset retirement obligations;

 

·                                          reviewingdisclosure requirements for commitments and contingencies;

 

·                                          reviewingadjustments raised by the independent auditors, whether or not included in thefinancial statements;

 

·                                          reviewingunresolved differences between management and the independent auditors, if any;

 

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

 

·                                          determinethrough inquiry if there are any related party transactions and ensure thenature and extent of such 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 annualbasis, the Committee shall review and discuss with the auditors allrelationships the auditors have with the Trust and the Company to determine theauditors’ independence. In addition, the Committee will ensure the rotation ofpartners on the audit engagement team in accordance with applicable law and, inorder to ensure continuing auditor independence, consider the rotation of theaudit firm itself;

 

·                                          be directlyresponsible for appointing, compensating, retaining and overseeing the work ofthe independent auditors engaged for the purpose of issuing an auditors’ reportor performing other audit, review or attest services for the Trust, includingthe resolution of disagreements between management and the independent auditorregarding financial reporting, and the independent auditors shall reportdirectly to the Committee;

 

·                                          review andevaluate the performance of the lead partner of the independent auditors;

 

·                                          review thebasis of management’s recommendation for the appointment of independentauditors and recommend to the board appointment of independent auditors andtheir compensation;

 

·                                          review theterms of engagement and the overall audit plan (including the materialitylevels to be applied) of the independent auditors, including theappropriateness and reasonableness of the auditors’ fees;

 

·                                          when there isto be a change in auditors, review the issues related to the change and theinformation to be included in the required notice to securities regulators ofsuch change; and

 

·                                          review andpre-approve any audit and permitted non-audit services to be provided by theindependent auditors’ firm and consider the impact on the independence of theauditors.

 

·                                          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.

 

·                                          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 Committee shall also review annually with the independentauditors

 

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theirplan for their audit and, upon completion of the audit, their reports upon thefinancial statements 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 Committee may delegate to one or more members ofthe Committee authority to pre-approve non-audit services in satisfaction ofthis requirement and if such delegation occurs, the pre-approval of non-auditservices by the Committee member to whom authority has been delegated must bepresented to the Committee at its first scheduled meeting following suchpre-approval. The Committee shall be entitled to adopt specific policies andprocedures for the engagement of non audit services if:

 

·                                          thepre-approval policies and procedures are detailed as to the particular service;

 

·                                          the Committeeis informed of each non-audit service so approved; and

 

·                                          the proceduresdo not include delegation of the Committee’s responsibilities to management.

 

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

 

·                                          the aggregateamount of all non audit services that were not pre approved is reasonablyexpected to constitute no more than 5% of the total amount of fees paid by theTrust and its subsidiary entities to the auditors during the fiscal year inwhich the services are provided;

 

·                                          the Trust orthe subsidiary entity, as the case may be, did not recognize the services asnon-audit services at the time of the engagement;

 

·                                          the servicesare promptly brought to the attention of the Committee and approved, prior tocompletion of the audit, by the Committee or by one or more of its members towhom authority to 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.

 

·                                          Review and discuss major financialrisk exposures and the steps management has taken to monitor and control suchexposures. Discuss guidelines and policies to govern the process by which riskassessment and management is undertaken.

 

·                                          Establish procedures independent of management for:

 

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·                                          the receipt,retention and treatment of complaints received by the Trust regardingaccounting, internal accounting controls, or auditing matters; and

 

·                                          theconfidential, anonymous submission by employees of the Trust of concernsregarding questionable accounting 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 CEO, the CFO and the independentauditors, the matters required to be reviewed with those persons in connectionwith any certificates required by applicable laws, regulations or stockexchange requirements to be provided by the CEO and CFO.

 

·                                          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 “proforma” 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) MultilateralInstrument 52-110 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 NI 52-110.

 

·                                          The Secretary to the Board shall act asSecretary of the Committee.

 

·                                          A quorum shall be a majority of the members ofthe Committee.

 

·                                          All of the members must be financially literatewithin the meaning of NI 52-110 and Section 303A.07(a) of theCorporate Governance Rules of the New York Stock Exchange unless the Boardhas determined to rely on an exemption in NI 52-110. Being “financiallyliterate” means members have the ability to read and understand a set offinancial statements that present a breadth and level of complexity ofaccounting issues that are generally comparable to the breadth and complexityof issues that can reasonably be expected to be raised by the Trust’s financialstatements. In addition, at least one member of the Committee must haveaccounting or related financial management expertise, as the Board interpretssuch qualification in its business judgment.

 

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·                                          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 any proposed nominee of PWPL serves on the auditcommittee of more than three public companies, the Board will make adetermination as to whether such simultaneous services would impair the abilityof such member to effectively serve on the Company’s Audit Committee and willdisclose such determination in the Trust’s annual information circular andannual report on Form 40-F filed with the Securities and ExchangeCommission.

 

**Meetings**

** **

·                                          The Committee shallmeet at least four times per year and/or as deemed appropriate by the CommitteeChair. As part of its job tofoster open communication, the Committee should meet at least annually withmanagement, internal auditors (if any) and the independent auditors in separateexecutive sessions to discuss any matters that the Committee or each of thesegroups believe should be discussed privately. In addition, the Committee or atleast its Chair should meet with the independent auditors and managementquarterly to review the Trust’s financials. The Committee should also meet withmanagement and independent auditors on an annual basis to review and discussannual financial statements and the management’s discussion and analysis offinancial conditions and results of operations.

 

·                                          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 VP Finance or their designates shall be available to attend atall meetings of the Committee upon the invitation of the Committee.

 

·                                          The Controller,Treasurer and such other staff as appropriate to provide information to theCommittee shall 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 the Committee meeting will subsequently beprovided to all Board members as soon as practicable.

 

·                                          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 tocooperate as requested by the 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.

 

·                                          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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