**Exhibit 99.1**

**PENNWEST ENERGY TRUST**

**2006Annual Information Form**

 

 

**March22, 2007**

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**TABLEOF CONTENTS**
|                                                             | ** ** | **Page** |
|-------------------------------------------------------------|------------|----------|
| GLOSSARY OF TERMS                                           |       | 1        |
| ABBREVIATIONS                                               |       | 2        |
| CONVERSIONS                                                 |       | 2        |
| SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS           |       | 3        |
| PENN WEST ENERGY TRUST                                      |       | 5        |
| GENERAL DEVELOPMENT OF THE BUSINESS                         |       | 6        |
| DESCRIPTION OF OUR BUSINESS                                 |       | 6        |
| STATEMENT OF RESERVES DATA                                  |       | 7        |
| OTHER OIL AND GAS INFORMATION                               |       | 19       |
| CAPITALIZATION OF PENN WEST PETROLEUM LTD.                  |       | 29       |
| INFORMATION RELATING TO THE TRUST                           |       | 31       |
| CORPORATE GOVERNANCE                                        |       | 33       |
| AUDIT COMMITTEE DISCLOSURES                                 |       | 37       |
| DISTRIBUTIONS TO UNITHOLDERS                                |       | 40       |
| MARKET FOR SECURITIES                                       |       | 40       |
| INDUSTRY CONDITIONS                                         |       | 41       |
| RISK FACTORS                                                |       | 46       |
| MATERIAL CONTRACTS                                          |       | 54       |
| TRANSFER AGENT AND REGISTRAR                                |       | 54       |
| INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL  TRANSACTIONS |       | 54       |
| INTERESTS OF EXPERTS                                        |       | 54       |
| ADDITIONAL INFORMATION                                      |       | 55       |

 

APPENDICES:

“A” — REPORT OF MANAGEMENT AND DIRECTORS ON RESERVESDATA AND OTHER INFORMATION“B” — GLJ REPORT ON RESERVES DATA“C” — AUDIT COMMITTEE MANDATE

 

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**GLOSSARYOF TERMS**

Capitalized terms in thisAnnual Information Form have the meanings set forth below:

***Entities***

**Board ofDirectors** means the Board of Directors of Penn West PetroleumLtd.

**PennWest**, **we**, **us, our** or**Trust**means Penn West Energy Trust and all its controlled entitieson a consolidated basis.

**PennWest Partnership**means Penn West Petroleum, a generalpartnership, between Penn West Petroleum Ltd. and Trocana Resources Inc., awholly owned subsidiary of Penn West Petroleum Ltd.

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

**Unitholders**means holders of our Trust Units.

***IndependentEngineering***

**GLJ**means GLJ Petroleum Consultants Ltd., independent petroleum consultants ofCalgary, Alberta.

**GLJReport** means the report prepared by GLJ dated February 28,2007 evaluating the crude oil, natural gas and natural gas liquids reservesattributable to certain of our oil and natural gas assets at December 31,2006.

***Securities***

**Notes**means the unsecured subordinated promissory notes issued by Penn West PetroleumLtd. and Petrofund Ventures Trust now held by the Trust.

**NPI**means the net profit interests in the petroleum substances owned by our whollyowned subsidiaries and trusts held by the Trust.

**Trust Unit**means a unit issued by us, each unit representing an equal undivided beneficialinterest in our assets.

***Agreements***

**AdministrationAgreement** means the agreement dated May 31, 2005 between theTrustee and Penn West Petroleum Ltd. pursuant to which Penn West Petroleum Ltd.agrees to provide certain administrative and advisory services in connectionwith the Trust.

**NPIAgreements** means the net profits interest agreement dated May31, 2005 between Penn West Petroleum Ltd. and the Trust, the net profitinterest agreement dated November 8, 2005 between Penn West Petroleum Ltd. andthe Trust and the net profits interest agreement dated November 8, 2005 betweenPetrofund Ventures Trust, one of our wholly owned trusts, and the Trust.

**Trust Indenture**means the amended and restated trust indenture between the Trustee and Penn West Petroleum Ltd., amended andrestated as of June 30, 2006.

***Others***

**PetrofundMerger** means the plan of arrangement under the *Business Corporations Act* (Alberta)pursuant to which Penn West acquired Petrofund Energy Trust.

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**ABBREVIATIONS**
| **Oil and Natural Gas Liquids** |   | **Natural Gas**                     |   |
|---------------------------------|--------|-------------------------------------|--------|
| bbl                             |   | barrel  or barrels                  |   | GJ |   | gigajoule |   |
| bbl/d                           |   | barrels  per day                    |   | Mcf |   | thousand  cubic feet |   |
| Mbbl                            |   | thousand  barrels                   |   | MMcf |   | million  cubic feet |   |
| MMbbl                           |   | million  barrels                    |   | Bcf |   | billion  cubic feet |   |
| NGLs                            |   | natural  gas liquids                |   | Mcf/d |   | thousand  cubic feet per day |   |
| MMboe                           |   | million  barrels of oil equivalent  |   | MMcf/d |   | million  cubic feet per day |   |
| Mboe                            |   | thousand  barrels of oil equivalent |   | m3 |   | cubic  metres |   |
| boe/d                           |   | barrels of oil  equivalent per day  |   | 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.                                                                                                                                                                                                                                                                                                                                                           |
| °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$        |       | one million dollars                                                                                                                                                                                                                                                                                                                                                                      |

**CONVERSIONS**

The following table setsforth certain conversions between Standard Imperial Units and the InternationalSystem 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        |       | 2.471                |       |
| gigajoules                |       | MMbtu        |       | 0.950                |       |
| MMbtu                     |       | gigajoules   |       | 1.0526               |       |

All dollar amounts set forth in this AnnualInformation Form are in Canadian dollars, except where otherwise indicated.

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**SPECIALNOTE REGARDING FORWARD-LOOKING STATEMENTS**

Certain statementscontained in this Annual Information Form and in certain documents incorporatedby reference into this Annual Information Form, constitute forward-lookingstatements.  These statements relate tofuture events or our future performance. All statements other than statements of historical fact may beforward-looking statements. Forward-looking statements are often, but not always, identified by theuse of words such as “seek”, “anticipate”, “budget”, “plan”, “continue”, “estimate”,“expect”, “forecast”, “may”, “will”, “project”, “predict”, “potential”, “targeting”,“intend”, “could”, “might”, “should”, “believe” and other similarexpressions.  These statements involveknown and unknown risks, uncertainties and other factors that may cause actualresults or events to differ materially from those anticipated in suchforward-looking statements.  We believethe expectations reflected in those forward-looking statements are reasonablebut no assurance can be given that these expectations will prove to be correctand such forward-looking statements included in, or incorporated by referenceinto, this Annual Information Form should not be unduly relied upon.  These statements speak only as of the date ofthis Annual Information Form or as of the date specified in the documentsincorporated by reference into this Annual Information Form, as the case maybe.

In particular, thisAnnual Information Form, and the documents incorporated by reference, containforward-looking statements based on assumptions pertaining to the following:

·                  the performance characteristics ofour oil and natural gas properties;

·                  oil and natural gas productionlevels;

·                  the size of our oil and natural gasreserves;

·                  projections of market prices andcosts and the related sensitivities of distributions;

·                  supply and demand for oil and naturalgas;

·                  expectations regarding our ability toraise capital and to continually add to reserves through acquisitions anddevelopment;

·                  treatment under governmentalregulatory regimes and tax laws; and

·                  capitalexpenditures programs.

The actual results could differ materially from thoseresults anticipated in these forward-looking statements as a result of the riskfactors set forth below and elsewhere in this Annual Information Form:

·                  volatility in market prices for oiland natural gas;

·                  liabilities inherent in oil andnatural gas operations;

·                  uncertainties associated withestimating oil and natural gas reserves;

·                  competition for, among other things,capital, acquisitions of reserves, undeveloped lands and skilled personnel;

·                  incorrect assessments of the value ofacquisitions;

·                  geological, technical, drilling andprocessing problems;

·                  changes in income tax laws or changesin tax laws and incentive programs relating to the oil and gas industry andincome trusts; and

·                  theother factors discussed under “Risk Factors”.

The actual results coulddiffer materially from those results anticipated in these forward-lookingstatements, which are based on assumptions, including: the market prices foroil and natural gas; the continued availability of capital, acquisitions ofreserves, undeveloped lands and skilled personnel; the continuation of thecurrent tax and regulatory regime; and other assumptions contained in thisAnnual Information Form.

Statements relating to “reserves”or “resources” are deemed to be forward-looking statements, as theyinvolve the implied assessment, based on certain estimates and assumptions,that the resources and reserves described can be profitably produced in thefuture.  Readers are cautioned that theforegoing lists of factors are not exhaustive. The forward-looking statements contained in this AnnualInformation Form and the documents incorporated by reference herein areexpressly qualified by this cautionary statement.  We do not undertake any obligation topublicly update or revise any forward-looking statements.

**Description of Cash Flow**

This Annual InformationForm refers to cash flow and cash flow from operations derived from cash flowfrom operating activities (before changes in non-cash working capital,expenditures on abandonment and reclamation costs and payments for surrenderedstock options).  Cash flow as presenteddoes not have any standardized meaning prescribed by Canadian generallyaccepted accounting principles, (“GAAP”) and therefore it may not be comparablewith the calculation of similar 

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measures for otherentities.  Cash flow as presented is notintended to represent operating cash flow or operating profits for the periodnor should it be viewed as an alternative to cash flow from operatingactivities, net earnings or other measures of financial performance calculatedin accordance with Canadian GAAP.

For more information, see“Management’s Discussion and Analysis” for the year ended December 31,2006, which includes a reconciliation of “cash flow” to cash flow fromoperating activities which has been filed on SEDAR at www.sedar.com.  Cash flow is cash flow from operatingactivities before changes in non cash working capital, expenditures on sitereclamation and restoration and payments for surrendered stock options.

**Access to Documents**

Any document referred toin this Annual Information Form and described as being filed on SEDAR at *www.sedar.com* (including those documentsreferred to as being incorporated by reference in this Annual Information Form)may be obtained free of charge from us at 2200, 425 — 1st Street S.W., Calgary, Alberta, T2P 3L8.

 

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**PENNWEST ENERGY TRUST**

**General**

We are an open-endinvestment trust created on April 22, 2005 under the laws of the Provinceof Alberta pursuant to the Trust Indenture as amended and restated onJune 30, 2006. At that time, CIBC Mellon Trust Company was appointed astrustee under the Trust Indenture for a three year period.  The beneficiaries of the Trust are holders ofthe Trust Units.  Our principal and headoffice is located at 2200, 425 — 1st Street S.W., Calgary, Alberta, T2P 3L8.

We commenced operationsin our current structure on June 1, 2005 after the completion of a plan ofarrangement under the *Business CorporationsAct* (Alberta).  Pursuant tothis plan of arrangement, holders of common shares of Penn West Petroleum Ltd.received three (3) Trust Units for each one (1) of their common shares.

**Inter-Corporate Relationships**

The following are thenames, the percentage of voting securities that we own and the jurisdiction ofincorporation, continuance or formation of our material subsidiaries andpartnerships either, direct or indirect, as at the date hereof.
| ** **               | ** ** | **Percentage of voting   securities  (directly or indirectly)** | ** ** | **Nature of Entity** | ** ** | **Jurisdiction of  Incorporation/  Formation** |
|--------------------------|------------|-----------------------------------------------------------------|------------|----------------------|------------|------------------------------------------------|
| Penn West Petroleum Ltd. |       | 100%                                                            |       | Corporation          |       | Alberta                                        |
| Penn West Petroleum      |       | 100%                                                            |       | General  Partnership |       | Alberta                                        |

**Our Organization Structure**

The following diagramdescribes the inter-corporate relationships among us and our materialsubsidiaries.

** **

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Notes:

(1)                                  The Unitholders own 100 percent ofthe Trust’s equity.

(2)                                  Cash distributions are made on a monthlybasis to Unitholders based upon our cash flow. Our primary sources of cash flow are payments from  Penn West Petroleum Ltd. pursuant to the NPIsand interest on the principal amount of the Notes.  In addition, we receive payments on  one of the NPIs and interest on one of theNotes from Petrofund Ventures Trust.

(3)                                  Penn West AcquisitionCo Inc., Penn WestPetroleum Ltd., Penn West Exploration Ltd. and Northern Reef Exploration Ltd.were amalgamated as of January 1, 2006 under the name Penn West PetroleumLtd..  Penn West was further amalgamatedwith Penn West (PTF) Energy Ltd. and Petrofund Alternative Energy Ltd. onJanuary 1, 2007 under the name Penn West Petroleum Ltd.

(4)                                  Penn West Petroleum Ltd. and TrocanaResources Inc. currently comprise the Penn West Partnership.

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**GENERAL DEVELOPMENT OF THEBUSINESS**

**History and Development**

On May 31, 2005,Penn West Petroleum Ltd. completed a plan of arrangement whereby holders ofcommon shares of Penn West Petroleum Ltd. received three (3) Trust Unitsfor each one (1) of their common shares.

Effective June 30,2006 Penn West completed the Petrofund Merger, pursuant to which Penn Westacquired Petrofund Energy Trust on the basis of an exchange of .60 of a TrustUnit (an aggregate of 70.7 million Trust Units).  A special cash distribution in the amountof $1.10 per unit (an aggregate of $129.6 million) of PetrofundEnergy Trust, of which $0.10 per unit was to align the distribution recorddates of the trusts, was made immediately prior to the completion of thePetrofund Merger to the holders of units of Petrofund Energy Trust.  As a result of the acquisition pursuant tothe Petrofund Merger, Penn West acquired 70.9 MMbbl of light/medium crudeoil and NGLs, 0.7 MMbbl of heavy oil and 279.3 Bcf of natural gas on aproved reserve basis and 93.8 MMbbl of light/medium crude oil and NGLs,1.0 MMbbl of heavy oil, 371.2 Bcf of natural gas on a proved plusprobable reserve basis and 352,600 net acres of undeveloped land.  Penn West assumed $610.4 million of bankindebtedness of Petrofund Energy Trust in connection with the Petrofund Merger.

For further informationin relation to the Petrofund Merger, see note 3 of our consolidated financialstatements for the year ended December 31, 2006, which is hereby incorporatedby reference and which has been filed on SEDAR at www.sedar.com.

**DESCRIPTIONOF OUR BUSINESS**

**Overview**

Our principal undertakingis to issue Trust Units and to acquire and hold securities of subsidiaries,trusts and partnerships, net profits interests, royalties, notes and otherinterests.  Our direct and indirectsubsidiaries and partnerships carry on the business of acquiring, developing,exploiting and holding interests in petroleum and natural gas properties andassets related thereto.  A portion of thecash flow from the assets is paid from Penn West Petroleum Ltd. and PetrofundVentures Trust to the Trust by way of interest and principal payments on theNotes and payments from Penn West Petroleum Ltd. and Petrofund Ventures Trustto the Trust under the NPI Agreements.

The Board of Directorsmay declare distributions payable to the Unitholders and allocate all or any ofour income to the Unitholders.  It iscurrently anticipated that the only income we will receive will be from PennWest Petroleum Ltd. and Petrofund Ventures Trust by way of interest received onthe principal amount of Notes and payments pursuant to the NPI.  We make monthly cash distributions toUnitholders from this income after any expenses and any cash redemptions ofTrust Units.

Cash distributions aremade on or about the 15th day of each monthto Unitholders of record on or about the last calendar day of the immediatelypreceding month.

***Penn WestPetroleum Ltd.***

Penn West Petroleum Ltd.is a corporation amalgamated and subsisting pursuant to the laws ofAlberta.  Penn West Petroleum Ltd. isactively engaged in the business of oil and natural gas exploitation,development, acquisition and production in Canada.  The Trust is the sole shareholder of PennWest Petroleum Ltd.

The registered and headoffice of Penn West Petroleum Ltd. is located at 2200, 425 — 1st Street S.W., Calgary, Alberta, T2P 3L8.

***Notes***

The Notes evidence theindebtedness of Penn West Petroleum Ltd. and Petrofund Ventures Trust to theTrust in connection with the plan of arrangement completed on May 31, 2005 andadditional promissory notes acquired on the acquisition of Petrofund EnergyTrust pursuant to the Petrofund Merger. The Notes from Penn West Petroleum Ltd. are unsecured and subordinatedto senior indebtedness and bear interest at rates ranging from11.25 percent to 13.00 percent per annum and require principalpayments at dates ranging from May 31, 2017 to January 1, 2019. TheNote from Petrofund Ventures Trust bears interest at a rate of six percentper annum and is payable on demand.

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***NPI***

The Trust is a party toNPI Agreements with Penn West Petroleum Ltd. and Petrofund Ventures Trustpursuant to which we have the right to receive the NPIs on petroleum andnatural gas rights held by Penn West Petroleum Ltd. and Petrofund VenturesTrust from time to time.  Pursuant to theterms of the agreements, we are entitled to a payment from Penn West PetroleumLtd. and Petrofund Ventures Trust for each month equal to the amount by which99 percent of the gross proceeds from the sale of production attributableto the property interests of Penn West Petroleum Ltd. and Petrofund VenturesTrust for such month exceeds 99 percent of certain deductible costs forsuch period.  Deductible costs generallyinclude capital expenditures, royalties and operating costs related to oil andgas activities.  The term of theagreement is for as long as there are petroleum and natural gas rights to whichthe NPIs apply.

**Proposed Federal Tax Changes**

OnOctober 31, 2006 the Federal Minister of Finance proposed to apply a taxat the trust level on distributions of certain income from publicly tradedmutual fund trusts at rates of tax comparable to the combined federal andprovincial corporate tax and to treat such distributions as dividends to theunitholders (the “October 31 Proposals”). On December 21, 2006 the Federal Minister of Finance released draftlegislation to implement the October 31 Proposals pursuant to which,commencing January 1, 2011 (provided Penn West only experiences “normalgrowth” and no “undue expansion” before then) certain distributions from uswhich would have otherwise been taxed as ordinary income will be characterizedas dividends to our Unitholders and will be subject to tax at corporate ratesat the Trust level.  Assuming theOctober 31 Proposals are ultimately enacted in their current form, theimplementation of such legislation would be expected to result in adverse taxconsequences to us and certain Unitholders (including most particularlyUnitholders that are tax deferred or non-residents of Canada).

Managementbelieves that the October 31 Proposals have reduced the market value ofthe Trust Units, which would be expected to increase the cost to Penn West ofraising capital in the public capital markets. In addition, management believes that the October 31 Proposals areexpected to: (a) substantially eliminate the competitive advantage thatPenn West and other Canadian energy trusts enjoy relative to their corporatepeers in raising capital in a tax-efficient manner; and (b) place PennWest and other Canadian energy trusts at a competitive disadvantage relative toindustry competitors, including U.S. master limited partnerships, which willcontinue to not be subject to entity level taxation.  The October 31 Proposals are alsoexpected to make the Trust Units less attractive as consideration foracquisitions.  As a result, it may becomemore difficult for us to compete effectively for acquisition opportunities.  There can be no assurance that we will beable to reorganize our legal and tax structure to substantially mitigate theexpected impact of the October 31 Proposals.

**It is not known at this time when the October 31Proposals will be enacted by Parliament, if at all, or whether theOctober 31 Proposals will be enacted in the form currently proposed or newproposals will be proposed or enacted. See “Risk Factors — Proposed Federal Tax Changes” and “Risk Factors —Changes in Legislation”.**

**STATEMENTOF RESERVES DATA**

The Trust’s statement ofreserves data and other oil and gas information is set forth below (the “Statement”).  The effective date of the Statement isDecember 31, 2006 and the preparation date of the Statement isFebruary 28, 2007.  The Report ofManagement and Directors on Oil and Gas Disclosure on Form 51-101F3 and theReport on Reserves Data by GLJ on Form 51-102F2 are attached as AppendicesA and B to this Annual Information Form.

**Disclosure of Reserves Data**

The reserves data setforth below is based upon an evaluation by GLJ with an effective date ofDecember 31, 2006 contained in the GLJ Report dated February 28,2007.  The reserves data summarizes ouroil, natural gas liquids and natural gas reserves and the net present values offuture net revenue from these reserves using constant prices and costs andforecast prices and costs, not including the impact of any hedgingactivities.  The reserves data conformswith the requirements of National Instrument 51-101.  We engaged GLJ to provide an evaluation ofproved and proved plus probable reserves.  See also “Definitions and Notes to ReserveData Tables” below.

All of our reserves arein 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 constantprices and costs assumptions and forecast prices and costs assumptions will beattained and variances could be material. The recovery and reserves estimates of crude**

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**oil,natural gas liquids and natural gas reserves provided herein are estimates onlyand there is no guarantee that the estimated reserves will be recovered.  Actual crude oil, natural gas and natural gasliquid reserves may be greater than or less than the estimates providedherein.  For more information as to therisks involved, see “Risk Factors — Reserve Estimates” and “Risk Factors —Volatility of Oil and Natural Gas Prices”.**

We are a taxable entityunder the *Income Tax Act* (Canada)and, at the current time, are generally taxable only on income that is notdistributed or distributable to Unitholders. As we currently distribute all our taxable income to Unitholders asrequired by the Trust Indenture, future net revenue after income taxes is notincluded in the disclosure tables.  Theproposed tax on income trust distributions, proposed by the Federal FinanceMinister on October 31, 2006, has not been substantively enacted as incometax law.  See “Risk Factors — ProposedFederal Tax Changes”.

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

SUMMARY OF OIL AND GAS RESERVESAND NET PRESENT VALUES OF FUTURE NET REVENUEas of December 31, 2006CONSTANT PRICES AND COSTS

|                             | ** ** | **RESERVES**                            | ** ** |
|-----------------------------|------------|-----------------------------------------|------------|
| ** **                  | ** ** | **LIGHT AND MEDIUM OIL** | ** ** | **HEAVY OIL** | ** ** |
| **RESERVES CATEGORY**  | ** ** | **Gross  (Mbbl)**                       | ** ** | **Net  (Mbbl)** | ** ** | **Gross  (Mbbl)** | ** ** | **Net  (Mbbl)** | ** ** |
|                        |       |                                    |       |   |   |   |   |   |   |
| PROVED                      |       |                                    |       |   |   |   |   |   |   |
| Developed Producing         |       | 147,890                                 |       | 133,852 |   | 41,023 |   | 37,482 |   |
| Developed Non-Producing     |       | 6,469                                   |       | 5,876 |   | 3,197 |   | 2,586 |   |
| Undeveloped                 |       | 33,706                                  |       | 29,773 |   | 1,841 |   | 1,533 |   |
| TOTAL PROVED                |       | 188,066                                 |       | 169,500 |   | 46,062 |   | 41,600 |   |
|                        |       |                                    |       |   |   |   |   |   |   |
| PROBABLE                    |       | 50,788                                  |       | 44,969 |   | 13,950 |   | 12,225 |   |
|                        |       |                                    |       |   |   |   |   |   |   |
| TOTAL PROVED PLUS  PROBABLE |       | 238,853                                 |       | 214,469 |   | 60,012 |   | 53,825 |   |

 

|                             | ** ** | **RESERVES**         | ** ** |
|-----------------------------|------------|----------------------|------------|
| ** **                  | ** ** | **NATURAL GAS** | ** ** | **NATURAL GAS LIQUIDS** | ** ** |
| **RESERVES CATEGORY**  | ** ** | **Gross  (MMcf)**    | ** ** | **Net  (MMcf)** | ** ** | **Gross  (Mbbl)** | ** ** | **Net  (Mbbl)** | ** ** |
|                        |       |                 |       |   |   |   |   |   |   |
| PROVED                      |       |                 |       |   |   |   |   |   |   |
| Developed Producing         |       | 662,497              |       | 542,168 |   | 17,079 |   | 11,849 |   |
| Developed Non-Producing     |       | 46,379               |       | 35,964 |   | 1,025 |   | 692 |   |
| Undeveloped                 |       | 43,028               |       | 35,060 |   | 1,469 |   | 1,019 |   |
| TOTAL PROVED                |       | 751,904              |       | 613,191 |   | 19,573 |   | 13,560 |   |
|                        |       |                 |       |   |   |   |   |   |   |
| PROBABLE                    |       | 201,199              |       | 165,627 |   | 5,272 |   | 3,808 |   |
|                        |       |                 |       |   |   |   |   |   |   |
| TOTAL PROVED PLUS  PROBABLE |       | 953,104              |       | 778,819 |   | 24,845 |   | 17,368 |   |

 

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|                             | ** ** | **RESERVES**                       | ** ** |
|-----------------------------|------------|------------------------------------|------------|
| ** **                  | ** ** | **TOTAL OIL EQUIVALENT** | ** ** |
| **RESERVES CATEGORY**  | ** ** | **Gross  (Mboe)**                  | ** ** | **Net  (Mboe)** | ** ** |
|                        |       |                               |       |   |   |
| PROVED                      |       |                               |       |   |   |
| Developed Producing         |       | 316,409                            |       | 273,544 |   |
| Developed Non-Producing     |       | 18,421                             |       | 15,147 |   |
| Undeveloped                 |       | 44,188                             |       | 38,168 |   |
| TOTAL PROVED                |       | 379,018                            |       | 326,859 |   |
|                        |       |                               |       |   |   |
| PROBABLE                    |       | 103,542                            |       | 88,606 |   |
|                        |       |                               |       |   |   |
| TOTAL PROVED PLUS  PROBABLE |       | 482,560                            |       | 415,465 |   |

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

CONSTANT PRICESAND COSTS
| **RESERVES CATEGORY**  | ** ** | **0%  (MM$)** | ** ** | **5%  (MM$)** | ** ** | **10%  (MM$)** | ** ** | **15%  (MM$)** | ** ** | **20%  (MM$)** | ** ** |
|-----------------------------|------------|---------------|------------|---------------|------------|----------------|------------|----------------|------------|----------------|------------|
|                        |       |          |       |          |       |           |       |           |       |           |       |
| PROVED                      |       |          |       |          |       |           |       |           |       |           |       |
| Producing                   |       | 8,233         |       | 5,918         |       | 4,710          |       | 3,960          |       | 3,444          |       |
| Developed Non-Producing     |       | 547           |       | 303           |       | 207            |       | 157            |       | 126            |       |
| Undeveloped                 |       | 1,328         |       | 741           |       | 462            |       | 304            |       | 207            |       |
| TOTAL PROVED                |       | 10,108        |       | 6,961         |       | 5,378          |       | 4,421          |       | 3,776          |       |
|                        |       |          |       |          |       |           |       |           |       |           |       |
| PROBABLE                    |       | 2,982         |       | 1,575         |       | 995            |       | 697            |       | 522            |       |
|                        |       |          |       |          |       |           |       |           |       |           |       |
| TOTAL PROVED PLUS  PROBABLE |       | 13,090        |       | 8,536         |       | 6,373          |       | 5,118          |       | 4,298          |       |

TOTAL FUTURE NET REVENUE(UNDISCOUNTED)as of December 31, 2006CONSTANT PRICES AND COSTS
| **RESERVES  CATEGORY**         | ** ** | **REVENUE  (MM$)** | ** ** | **ROYALTIES  (MM$)** | ** ** | **OPERATING  COSTS  (MM$)** | ** ** | **DEVELOPMENT  COSTS  (MM$)** | ** ** | **WELL  ABANDONMENT  COSTS  (MM$)** | ** ** | **FUTURE NET  REVENUE  BEFORE  INCOME  TAXES  (MM$)** | ** ** |
|--------------------------------|------------|--------------------|------------|----------------------|------------|-----------------------------|------------|-------------------------------|------------|-------------------------------------|------------|------------------------------------------------------------|------------|
|                           |       |               |       |                 |       |                        |       |                          |       |                                |       |                                                       |       |
| Proved Reserves                |       | 19,795             |       | 2,595                |       | 6,130                       |       | 666                           |       | 296                                 |       | 10,108                                                     |       |
|                           |       |               |       |                 |       |                        |       |                          |       |                                |       |                                                       |       |
| Proved Plus Probable  Reserves |       | 25,121             |       | 3,333                |       | 7,411                       |       | 982                           |       | 305                                 |       | 13,090                                                     |       |

 

 

9

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FUTURE NET REVENUEBY PRODUCTION GROUPas of December 31, 2006CONSTANT PRICES AND COSTS
| **RESERVES CATEGORY**     | ** ** | **PRODUCTION GROUP**      | ** ** | **FUTURE NET REVENUE  BEFORE INCOME TAXES  (discounted at 10%/year)  (MM$)** | ** ** |
|--------------------------------|------------|--------------------------------|------------|------------------------------------------------------------------------------------------------------------|------------|
|                           |       |                           |       |                                                                                                       |       |
| Proved Reserves                |       | Light  and Medium Crude Oil(1) |       | 3,337                                                                                                      |       |
|                           |       | Heavy  Oil(1)                  |       | 557                                                                                                        |       |
|                           |       | Natural  Gas(2)                |       | 1,484                                                                                                      |       |
| TOTAL                          |       |                           |       | 5,378                                                                                                      |       |
|                           |       |                           |       |                                                                                                       |       |
| Proved Plus Probable  Reserves |       | Light  and Medium Crude Oil(1) |       | 3,910                                                                                                      |       |
|                           |       | Heavy  Oil(1)                  |       | 687                                                                                                        |       |
|                           |       | Natural  Gas (2)               |       | 1,776                                                                                                      |       |
| TOTAL                          |       |                           |       | 6,373                                                                                                      |       |

----

Notes:

(1)                                  Including solution gas and otherby-products.

(2)                                  Including by-products but excludingsolution gas.

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

SUMMARY OF OIL AND GAS RESERVESAND NET PRESENT VALUES OF FUTURE NET REVENUEas of December 31, 2006FORECAST PRICES AND COSTS

|                            | ** ** | **RESERVES**                            | ** ** |
|----------------------------|------------|-----------------------------------------|------------|
| ** **                 | ** ** | **LIGHT AND MEDIUM OIL** | ** ** | **HEAVY OIL** | ** ** |
| **RESERVES CATEGORY** | ** ** | **Gross  (Mbbl)**                       | ** ** | **Net  (Mbbl)** | ** ** | **Gross  (Mbbl)** | ** ** | **Net  (Mbbl)** | ** ** |
|                       |       |                                    |       |   |   |   |   |   |   |
| PROVED                     |       |                                    |       |   |   |   |   |   |   |
| Developed  Producing       |       | 146,914                                 |       | 132,968 |   | 40,945 |   | 37,366 |   |
| Developed  Non-Producing   |       | 6,569                                   |       | 5,970 |   | 3,118 |   | 2,490 |   |
| Undeveloped                |       | 33,447                                  |       | 29,672 |   | 1,839 |   | 1,525 |   |
| TOTAL PROVED               |       | 186,929                                 |       | 168,611 |   | 45,902 |   | 41,381 |   |
|                       |       |                                    |       |   |   |   |   |   |   |
| PROBABLE                   |       | 50,880                                  |       | 45,152 |   | 14,030 |   | 12,255 |   |
| TOTAL PROVED PLUS PROBABLE |       | 237,809                                 |       | 213,763 |   | 59,932 |   | 53,636 |   |

 

|                            | ** ** | **RESERVES**         | ** ** |
|----------------------------|------------|----------------------|------------|
| ** **                 | ** ** | **NATURAL GAS** | ** ** | **NATURAL GAS LIQUIDS** | ** ** |
| **RESERVES CATEGORY** | ** ** | **Gross  (MMcf)**    | ** ** | **Net  (MMcf)** | ** ** | **Gross  (Mbbl)** | ** ** | **Net  (Mbbl)** | ** ** |
|                       |       |                 |       |   |   |   |   |   |   |
| PROVED                     |       |                 |       |   |   |   |   |   |   |
| Developed  Producing       |       | 667,612              |       | 546,548 |   | 17,093 |   | 11,874 |   |
| Developed  Non-Producing   |       | 46,580               |       | 36,057 |   | 1,045 |   | 707 |   |
| Undeveloped                |       | 43,433               |       | 35,445 |   | 1,452 |   | 1,009 |   |
| TOTAL PROVED               |       | 757,625              |       | 618,049 |   | 19,590 |   | 13,589 |   |
|                       |       |                 |       |   |   |   |   |   |   |
| PROBABLE                   |       | 203,213              |       | 167,230 |   | 5,303 |   | 3,833 |   |
| TOTAL PROVED PLUS PROBABLE |       | 960,838              |       | 785,280 |   | 24,893 |   | 17,422 |   |

 

10

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|                            | ** ** | **RESERVES**                       | ** ** |
|----------------------------|------------|------------------------------------|------------|
| ** **                 | ** ** | **TOTAL OIL EQUIVALENT** | ** ** |
| **RESERVES CATEGORY** | ** ** | **Gross  (Mboe)**                  | ** ** | **Net  (Mboe)** | ** ** |
|                       |       |                               |       |   |   |
| PROVED                     |       |                               |       |   |   |
| Developed  Producing       |       | 316,221                            |       | 273,299 |   |
| Developed  Non-Producing   |       | 18,494                             |       | 15,177 |   |
| Undeveloped                |       | 43,977                             |       | 38,113 |   |
| TOTAL PROVED               |       | 378,692                            |       | 326,589 |   |
|                       |       |                               |       |   |   |
| PROBABLE                   |       | 104,082                            |       | 89,112 |   |
| TOTAL PROVED PLUS PROBABLE |       | 482,774                            |       | 415,701 |   |

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

FORECAST PRICESAND COSTS
| **RESERVES CATEGORY** | ** ** | **0%  (MM$)** | ** ** | **5%  (MM$)** | ** ** | **10%  (MM$)** | ** ** | **15%  (MM$)** | ** ** | **20%  (MM$)** | ** ** |
|----------------------------|------------|---------------|------------|---------------|------------|----------------|------------|----------------|------------|----------------|------------|
|                       |       |          |       |          |       |           |       |           |       |           |       |
| PROVED                     |       |          |       |          |       |           |       |           |       |           |       |
| Developed  Producing       |       | 9,369         |       | 6,568         |       | 5,174          |       | 4,333          |       | 3,762          |       |
| Developed  Non-Producing   |       | 742           |       | 375           |       | 248            |       | 186            |       | 149            |       |
| Undeveloped                |       | 1,483         |       | 784           |       | 475            |       | 308            |       | 207            |       |
| TOTAL PROVED               |       | 11,593        |       | 7,727         |       | 5,897          |       | 4,826          |       | 4,118          |       |
|                       |       |          |       |          |       |           |       |           |       |           |       |
| PROBABLE                   |       | 3,847         |       | 1,891         |       | 1,152          |       | 793            |       | 588            |       |
|                       |       |          |       |          |       |           |       |           |       |           |       |
| TOTAL PROVED PLUS PROBABLE |       | 15,440        |       | 9,618         |       | 7,049          |       | 5,619          |       | 4,706          |       |

TOTAL FUTURE NETREVENUE(UNDISCOUNTED)as of December 31, 2006FORECAST PRICES AND COSTS
| **RESERVES CATEGORY**    | ** ** | **REVENUE  (MM$)** | ** ** | **ROYALTIES  (MM$)** | ** ** | **OPERATING  COSTS  (MM$)** | ** ** | **DEVELOPMENT  COSTS  (MM$)** | ** ** | **WELL  ABANDONMENT  COSTS  (MM$)** | ** ** | **FUTURE NET  REVENUE  BEFORE  INCOME  TAXES  (MM$)** | ** ** |
|-------------------------------|------------|--------------------|------------|----------------------|------------|-----------------------------|------------|-------------------------------|------------|-------------------------------------|------------|------------------------------------------------------------|------------|
|                          |       |               |       |                 |       |                        |       |                          |       |                                |       |                                                       |       |
| Proved Reserves               |       | 23,611             |       | 3,085                |       | 7,802                       |       | 718                           |       | 412                                 |       | 11,593                                                     |       |
|                          |       |               |       |                 |       |                        |       |                          |       |                                |       |                                                       |       |
| Proved Plus Probable Reserves |       | 30,781             |       | 4,059                |       | 9,762                       |       | 1,069                         |       | 451                                 |       | 15,440                                                     |       |

 

11

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FUTURE NET REVENUEBY PRODUCTION GROUPas of December 31, 2006FORECAST PRICES AND COSTS

| RESERVES CATEGORY         | ** ** | **PRODUCTION GROUP**       | ** ** | **FUTURE NET REVENUE   BEFORE INCOME TAXES   (discounted at 10%/year)  (MM$)** | ** ** |
|--------------------------------|------------|---------------------------------|------------|------------------------------------------------------------------------------------------------------------------------|------------|
|                           |       |                            |       |                                                                                                                   |       |
| Proved  Reserves               |       | Light and Medium Crude  Oil (1) |       | 3,319                                                                                                                  |       |
|                           |       | Heavy Oil(1)                    |       | 588                                                                                                                    |       |
|                           |       | Natural Gas(2)                  |       | 1,990                                                                                                                  |       |
| TOTAL                          |       |                            |       | 5,897                                                                                                                  |       |
|                           |       |                            |       |                                                                                                                   |       |
| Proved  Plus Probable Reserves |       | Light and Medium Crude  Oil(1)  |       | 3,912                                                                                                                  |       |
|                           |       | Heavy Oil(1)                    |       | 731                                                                                                                    |       |
|                           |       | Natural Gas(2)                  |       | 2,406                                                                                                                  |       |
| TOTAL                          |       |                            |       | 7,049                                                                                                                  |       |

----

Notes:

(1)                                  Including solution gas and otherby-products.

(2)                                  Including by-products but excludingsolution gas.

**Definitionsand Notes to Reserves Data Tables**

In the tables set forthabove in “Disclosure of Reserves Data” and elsewhere in this Annual InformationForm the following definitions and other notes are applicable:

1.                                       “**Gross**”means:

(a)                                  inrelation to our interest in production and reserves, our interest (operatingand non-operating) before deduction of royalties and without including anyroyalty interest of ours;

(b)                                 inrelation to wells, the total number of wells in which we have an interest; and

(c)                                  inrelation to properties, the total area of properties in which we have aninterest.

2.                                       “**Net**”means:

(a)                                  inrelation to our interest in production and reserves, our interest (operatingand non-operating) after deduction of royalty obligations, plus our royaltyinterests in production or reserves;

(b)                                 inrelation to wells, the number of wells obtained by aggregating our workinginterest in each of our gross wells; and

(c)                                  inrelation to our interest in a property, the total area in which we have aninterest multiplied by the working interest we owned.

3.                                       Columns may not add due to rounding.

4.                                       The crude oil, natural gas liquids andnatural gas reserves estimates presented in the GLJ Report are based on thedefinitions and guidelines contained in the Canadian Oil and Gas EvaluationHandbook (“COGE Handbook”).  A summary ofthose definitions are set forth below:

**ReservesCategories**

Reserves are estimated remaining quantities of oil and natural gas andrelated substances anticipated to be recoverable from known accumulations, froma given date forward, based on:

12

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(a)                                  analysisof drilling, geological, geophysical and engineering data;

(b)                                 theuse of established technology; and

(c)                                  specifiedeconomic conditions.

Reserves are classified according to the degree of certainty associatedwith the estimates.

(a)                                  **Proved reserves**are those reserves that canbe estimated with a high degree of certainty to be recoverable. It is likely thatthe actual remaining quantities recovered will exceed the estimated provedreserves.

(b)                                 **Probable reserves** are those additionalreserves that are less certain to be recovered than proved reserves. It isequally likely that the actual remaining quantities recovered will be greateror less than the sum of the estimated proved plus probable reserves.

Other criteria that must also be met for the categorization of reservesare provided in the COGE Handbook.

Each of the reserves categories (proved and probable) may be dividedinto developed and undeveloped categories.

(a)                                  **Developed reserves** are those reserves thatare expected to be recovered from existing wells and installed facilities or,if facilities have not been installed, that would involve a low expenditure(for example, when compared to the cost of drilling a well) to put the reserveson production. The developed category may be subdivided into producing andnon-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)                                  **Developed non-producing reserves** are thosereserves that either have not been on production, or have previously been onproduction, but are shut-in, and the date of resumption of production isunknown.

(b)                                 **Undeveloped reserves** are those reservesexpected to be recovered from known accumulations where a significantexpenditure (for example, when compared to the cost of drilling a well) isrequired to render them capable of production. They must fully meet therequirements of the reserves classification (proved, probable) to which theyare assigned.

In multi-well pools, it may be appropriate to allocate total poolreserves between the developed and undeveloped categories or to subdivide thedeveloped reserves for the pool between developed producing and developednon-producing. This allocation should be based on the estimator’s assessment asto the reserves that will be recovered from specific wells, facilities andcompletion intervals in the pool and their respective development andproduction status.

***L*****evels of Certainty for Reported Reserves**

The qualitative certainty levels referred to in the definitions aboveare applicable to individual reserve entities (which refers to the lowest levelat which reserves calculations are performed) and to reported reserves (whichrefers to the highest level sum of individual entity estimates for whichreserves are presented). Reported reserves should target the following levelsof certainty under a specific set of economic conditions:

(a)                                  atleast a 90 percent probability that the quantities actually recovered willequal or exceed the estimated proved reserves; and

(b)                                 atleast a 50 percent probability that the quantities actually recovered willequal or exceed the sum of the estimated proved plus probable reserves.

13

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A qualitative measure of the certainty levels pertaining to estimatesprepared for the various reserves categories is desirable to provide a clearerunderstanding of the associated risks and uncertainties. However, the majorityof reserves estimates will be prepared using deterministic methods that do notprovide a mathematically derived quantitative measure of probability. Inprinciple, there should be no difference between estimates prepared usingprobabilistic or deterministic methods.

Additional clarification of certainty levels associated with reservesestimates and the effect of aggregation is provided in the COGE Handbook.

5.                                       **Forecast prices andcosts**

These are prices and costs that are generally acceptable as being areasonable outlook of the future.  To theextent that there are fixed or presently determinable future prices or costs towhich we are legally bound by a contractual or other obligation to supply aphysical product, including those for an extension period of a contract that islikely to be extended, those prices or costs shall be incorporated into theforecast prices.

The forecast cost and price assumptions include increases in wellheadselling prices and take into account inflation with respect to future operatingand capital costs.  Crude oil, naturalgas and natural gas liquids benchmark reference pricing, as atDecember 31, 2006, inflation and exchange rates utilized in the GLJ Reportwere as follows:

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONSas of December 31, 2006FORECAST 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)  %** | ** ** | **EXCHANGE   RATE(2)  ($US equals   $1 Cdn)** | ** ** |
| Forecast   |       |                                              |       |                                                  |       |                                         |       |                                          |       |                               |       |   |   |   |   |   |   |   |   |   |   |
| 2007       |       | 62.00                                             |       | 70.25                                                 |       | 39.25                                        |       | 61.25                                         |       | 7.20                               |       | 45.00 |   | 50.25 |   | 71.25 |   | 2.0 |   | 0.870 |   |
| 2008       |       | 60.00                                             |       | 68.00                                                 |       | 40.00                                        |       | 59.25                                         |       | 7.45                               |       | 43.50 |   | 50.25 |   | 69.25 |   | 2.0 |   | 0.870 |   |
| 2009       |       | 58.00                                             |       | 65.75                                                 |       | 39.75                                        |       | 57.25                                         |       | 7.75                               |       | 42.00 |   | 48.75 |   | 67.00 |   | 2.0 |   | 0.870 |   |
| 2010       |       | 57.00                                             |       | 64.50                                                 |       | 39.75                                        |       | 56.00                                         |       | 7.80                               |       | 41.25 |   | 47.75 |   | 65.75 |   | 2.0 |   | 0.870 |   |
| 2011       |       | 57.00                                             |       | 64.50                                                 |       | 40.25                                        |       | 56.00                                         |       | 7.85                               |       | 41.25 |   | 47.75 |   | 65.75 |   | 2.0 |   | 0.870 |   |
| 2012       |       | 57.50                                             |       | 65.00                                                 |       | 41.50                                        |       | 56.50                                         |       | 8.15                               |       | 41.50 |   | 48.00 |   | 66.25 |   | 2.0 |   | 0.870 |   |
| 2013       |       | 58.50                                             |       | 66.25                                                 |       | 42.50                                        |       | 57.75                                         |       | 8.30                               |       | 42.50 |   | 49.00 |   | 67.50 |   | 2.0 |   | 0.870 |   |
| 2014       |       | 59.75                                             |       | 67.75                                                 |       | 43.50                                        |       | 59.00                                         |       | 8.50                               |       | 43.25 |   | 50.25 |   | 69.00 |   | 2.0 |   | 0.870 |   |
| 2015       |       | 61.00                                             |       | 69.00                                                 |       | 44.25                                        |       | 60.00                                         |       | 8.70                               |       | 44.25 |   | 51.00 |   | 70.50 |   | 2.0 |   | 0.870 |   |
| 2016       |       | 62.25                                             |       | 70.50                                                 |       | 45.25                                        |       | 61.25                                         |       | 8.90                               |       | 45.00 |   | 52.25 |   | 72.00 |   | 2.0 |   | 0.870 |   |
| 2017       |       | 63.50                                             |       | 71.75                                                 |       | 46.00                                        |       | 62.50                                         |       | 9.10                               |       | 46.00 |   | 53.00 |   | 73.25 |   | 2.0 |   | 0.870 |   |
| Thereafter |       | +2                                                | %          | +2                                                    | %          | +2                                           | %          | +2                                            | %          | +2                                 | %          | +2 | % | +2 | % | +2 | % | 2.0 |   | 0.870 |   |

----

Notes:

(1)                                  Inflation rates for forecasting pricesand costs.

(2)                                  Exchange rates used to generate thebenchmark reference prices in this table.

Weighted average actual prices realized, including hedging activities,for the year ended December 31, 2006 were $7.47/Mcf for natural gas,$65.32/bbl for light and medium crude oil, $43.07/bbl for heavy oil and$54.31/bbl for natural gas liquids.

6.                                       **Constant prices andcosts**

These are actual prices and costs as at the effective date of theestimation, held constant throughout the estimated lives of the properties towhich the estimate applies.  To theextent that there are fixed or presently determinable 

14

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future prices or costs to which we are legally bound by a contractualor other obligation to supply a physical product, including those for anextension period of a contract that is likely to be extended, those prices orcosts shall be incorporated into the price for future years.

The constant crude oil and natural gas benchmark reference pricing andthe exchange rate utilized in the GLJ Report were as follows:

SUMMARY OF PRICING ASSUMPTIONSas of December 31, 2006CONSTANT PRICES AND COSTS

| OIL                                               | ** ** | ** **                                                        | ** ** | **EDMONTON LIQUID PRICES**                              | ** ** | ** **                                                | ** ** |
|---------------------------------------------------|------------|-------------------------------------------------------------------|------------|-------------------------------------------------------------------|------------|-----------------------------------------------------------|------------|
| **WTI   Cushing   Oklahoma  ($US/bbl)** | ** ** | **Edmonton   Par Price  40° API  ($Cdn/bbl)** | ** ** | **LLB Crude   Oil at   Hardisty  ($Cdn/bbl)** | ** ** | **Cromer   Medium  29.3° API  ($Cdn/bbl)** | ** ** | **NATURAL   GAS  AECO  ($Cdn/Mcf)** | ** ** | **Propane  ($Cdn/bbl)** | ** ** | **Butane  ($Cdn/bbl)** | ** ** | **Pentanes  Plus  ($Cdn/bbl)** | ** ** | **EXCHANGE   RATE(1)  ($US equals   $1 Cdn)** | ** ** |
| 60.85                                             |       | 67.58                                                             |       | 47.62                                                             |       | 59.47                                                     |       | 6.07 |   | 43.25 |   | 54.06 |   | 71.55 |   | 0.8581 |   |

----

Note:

(1)                                  The exchange rate used to generate thebenchmark reference prices in this table.

7.                                       **Future Development Costs**

The following table sets forth development costs deducted in theestimation of our future net revenue attributable to the reserve categoriesnoted below.

|                                    | ** ** | **Forecast Prices and Costs** | ** ** | **Constant Prices and Costs**                  | ** ** |
|------------------------------------|------------|----------------------------------------------|------------|---------------------------------------------------------------|------------|
| **Year**                           | ** ** | **Proved Reserves  (MM$)**              | ** ** | **Proved Plus Probable   Reserves (MM$)** | ** ** | **Proved Reserves (MM$)** | ** ** |
| 2007                               |       | 148                                          |       | 180                                                           |       | 148 |   |
| 2008                               |       | 166                                          |       | 213                                                           |       | 162 |   |
| 2009                               |       | 98                                           |       | 130                                                           |       | 94 |   |
| 2010                               |       | 73                                           |       | 99                                                            |       | 69 |   |
| 2011                               |       | 57                                           |       | 82                                                            |       | 53 |   |
| Total:  Undiscounted for all years |       | 718                                          |       | 1,069                                                         |       | 666 |   |
| Total: Discounted at  10%/year     |       | 518                                          |       | 732                                                           |       | 497 |   |

We expect to fund the development costs of thereserves through a combination of cash flow withheld from distributions, debt,the sale of existing assets and the issuance of Trust Units.

There can be no guarantee that funds will be availableor that we will allocate funding to develop all of the reserves attributed inthe GLJ Report.  Failure to develop thosereserves would have a negative impact on future production and cash flow andcould result in negative revisions to our reserves.

The interest and other costs of external funding arenot included in the reserves and future net revenue estimates and would reducereserves and future net revenue to some degree depending upon the fundingsources utilized.  We do not anticipatethat interest or other funding costs would make development of any propertyuneconomic.

8.                                       Estimated future well abandonment costsrelated to reserve wells have been taken into account by GLJ in determining theaggregate future net revenue therefrom.

9.                                       Both the constant and forecast price andcost assumptions assumed the continuance of current laws and regulations.

10.                                 All factual data supplied to GLJ wasaccepted as represented. No field inspection was conducted.

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

15

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**Reconciliations of Changes in Reserves and Future NetRevenue**

The following table setsforth the reconciliation of our net reserves as at December 31, 2006,using forecast price and cost estimates derived from the GLJ Report.

RECONCILIATION OFNET RESERVESBY PRINCIPAL PRODUCT TYPEFORECAST PRICES AND COSTS
| ** **              | ** ** | **LIGHT AND MEDIUM OIL** | ** ** | **HEAVY OIL**   | ** ** | **NATURAL GAS**                           | ** ** |
|-------------------------|------------|-----------------------------------------|------------|----------------------|------------|------------------------------------------------|------------|
| **FACTORS**             | ** ** | **Proved  (Mbbl)**                      | ** ** | **Probable  (Mbbl)** | ** ** | **Proved   Plus   Probable  (Mbbl)** | ** ** | **Proved  (Mbbl)** | ** ** | **Probable  (Mbbl)** | ** ** | **Proved   Plus   Probable  (Mbbl)** | ** ** | **Proved  (MMcf)** | ** ** | **Probable  (MMcf)** | ** ** | **Proved   Plus   Probable  (MMcf)** | ** ** |
| December 31, 2005       |       | 122,380                                 |       | 25,864               |       | 148,244                                        |       | 45,177 |   | 11,556 |   | 56,733 |   | 462,790 |   | 109,805 |   | 572,595 |   |
|                    |       |                                    |       |                 |       |                                           |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Extensions              |       | 39                                      |       | 15                   |       | 54                                             |       | 1,795 |   | 262 |   | 2,057 |   | 14,899 |   | 2,246 |   | 17,145 |   |
| Improved  Recovery(1)   |       | 3,106                                   |       | 4,156                |       | 7,262                                          |       | 553 |   | 248 |   | 801 |   | 8,767 |   | 1,468 |   | 10,235 |   |
| Technical  Revisions(2) |       | (3,268                                  | )          | (2,137               | )          | (5,405                                         | )          | (334 | ) | (49 | ) | (383 | ) | (4,901 | ) | (12,174 | ) | (17,075 | ) |
| Discoveries             |       | —                                  |       | —               |       | —                                         |       | — |   | — |   | — |   | 1,588 |   | 1,946 |   | 3,534 |   |
| Acquisitions            |       | 56,751                                  |       | 17,173               |       | 73,924                                         |       | 612 |   | 234 |   | 846 |   | 223,120 |   | 64,201 |   | 287,321 |   |
| Dispositions            |       | (125                                    | )          | (48                  | )          | (173                                           | )          | (213 | ) | (54 | ) | (267 | ) | (656 | ) | (316 | ) | (978 | ) |
| Economic Factors        |       | 612                                     |       | 129                  |       | 741                                            |       | 226 |   | 58 |   | 284 |   | 231 |   | 55 |   | 286 |   |
| Production              |       | (10,884                                 | )          | —               |       | (10,884                                        | )          | (6,435 | ) | — |   | (6,435 | ) | (87,789 | ) | — |   | (87,789 | ) |
|                    |       |                                    |       |                 |       |                                           |       |   |   |   |   |   |   |   |   |   |   |   |   |
| December 31, 2006       |       | 168,611                                 |       | 45,152               |       | 213,763                                        |       | 41,381 |   | 12,255 |   | 53,636 |   | 618,049 |   | 167,231 |   | 785,280 |   |
|                    |       |                                    |       |                 |       |                                           |       |   |   |   |   |   |   |   |   |   |   |   |   |

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Note:

(1)                                  Improved recovery includes the followinginfill drilling:
| Infill Drilling |   | 1,328 |   | 50 |   | 1,377 |   | 489 |   | 269 |   | 758 |   | 5,720 |   | 720 |   | 6,440 |   |
|-----------------|--------|-------|--------|----|--------|-------|--------|-----|--------|-----|--------|-----|--------|-------|--------|-----|--------|-------|--------|

 

|                         | ** ** | **NATURAL GAS LIQUIDS** | ** ** | **TOTAL OIL EQUIVALENT** | ** ** |
|-------------------------|------------|-----------------------------------|------------|------------------------------------|------------|
| **FACTORS**             | ** ** | **Proved  (Mbbl)**                | ** ** | **Probable  (Mbbl)**               | ** ** | **Proved Plus   Probable  (Mbbl)** | ** ** | **Proved  (Mboe)** | ** ** | **Probable  (Mboe)** | ** ** | **Proved Plus  Probable  (Mboe)** | ** ** |
|                    |       |                              |       |                               |       |   |   |   |   |   |   |   |   |
| December 31, 2005       |       | 9,560                             |       | 1,990                              |       | 11,550 |   | 254,249 |   | 57,711 |   | 311,960 |   |
|                    |       |                              |       |                               |       |   |   |   |   |   |   |   |   |
| Extensions              |       | 138                               |       | (27                                | )          | 111 |   | 4,455 |   | 624 |   | 5,080 |   |
| Improved  Recovery(1)   |       | 170                               |       | 46                                 |       | 216 |   | 5,290 |   | 4,695 |   | 9,985 |   |
| Technical  Revisions(2) |       | 589                               |       | (80                                | )          | 509 |   | (3,830 | ) | (4,295 | ) | (8,124 | ) |
| Discoveries             |       | —                            |       | 1                                  |       | 1 |   | 265 |   | 325 |   | 590 |   |
| Acquisitions            |       | 4,298                             |       | 1,905                              |       | 6,203 |   | 98,848 |   | 30,012 |   | 128,859 |   |
| Dispositions            |       | (6                                | )          | (2                                 | )          | (8 | ) | (453 | ) | (157 | ) | (610 | ) |
| Economic Factors        |       | 5                                 |       | 1                                  |       | 6 |   | 881 |   | 197 |   | 1,078 |   |
| Production              |       | 1,165                             |       | —                             |       | (1,165 | ) | (33,116 | ) | — |   | (33,116 | ) |
|                    |       |                              |       |                               |       |   |   |   |   |   |   |   |   |
| December 31, 2006       |       | 13,589                            |       | 3,834                              |       | 17,422 |   | 326,589 |   | 89,113 |   | 415,701 |   |

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Notes:

(1)                                  Improved recovery includes the followinginfill drilling:

| Infill Drilling |   | 131 |   | 14 |   | 145 |   | 2,901 |   | 453 |   | 3,354 |   |
|-----------------|--------|-----|--------|----|--------|-----|--------|-------|--------|-----|--------|-------|--------|

 

(2)                                  Technical Revisions include reclassificationof 1,558 Mbbl of proved oil reserves as heavy from light/medium and 1,692 Mbblproved and probable oil reserves as heavy from light/medium.

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RECONCILIATION OF CHANGES INNET PRESENT VALUES OF FUTURE NET REVENUEDISCOUNTED AT 10% PER YEARPROVED RESERVESCONSTANT PRICES AND COSTS
| **PERIOD AND FACTOR**                                           | ** ** | **2006  (MM$)** | ** ** |
|---------------------------------------------------------------------------|------------|-----------------|------------|
|                                                                      |       |            |       |
| Estimated Future Net  Revenue at Beginning of Year                        |       | 4,972           |       |
|                                                                      |       |            |       |
| Oil and Gas  Sales During Period Net of Production Costs and Royalties(1) |       | (1,277          | )          |
| Changes due to  Prices and Royalties Related to Forecast Production(2)    |       | (856            | )          |
| Development  Costs During the Period(3)                                   |       | 542             |       |
| Changes in  Forecast Development Costs(4)                                 |       | (544            | )          |
| Changes  Resulting from Extensions and Improved Recovery(5)               |       | 164             |       |
| Changes  Resulting from Discoveries(5)                                    |       | 4               |       |
| Changes Resulting  from Acquisitions of Reserves(5)                       |       | 1,907           |       |
| Changes  Resulting from Dispositions of Reserves(5)                       |       | (7              | )          |
| Discount  factor(6)                                                       |       | 497             |       |
| Net Change in  Income Taxes(7)                                            |       | —          |       |
| Changes  Resulting from Technical Reserves Revisions                      |       | (65             | )          |
| All Other  Changes(8)                                                     |       | 41              |       |
|                                                                      |       |            |       |
| Estimated Future Net Revenue at End of Year                               |       | 5,378           |       |

----

Notes:

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

(2)                                  The impact of changes in prices and othereconomic factors on future net revenue.

(3)                                  Actual capital expenditures relating tothe exploration, development and production of oil and gas reserves.

(4)                                  The change in forecast future developmentcosts.

(5)                                  End of period net present value of therelated reserves.

(6)                                  Estimated as 10 percent of thebeginning of period net present value.

(7)                                  The difference between forecast incometaxes at beginning of period and the actual taxes for the period plus forecastincome taxes at the end of period.  Withconversion to a trust, Penn West Petroleum Ltd. does not pay income tax.  See:  “OtherOil and Gas Information — Tax Horizon” and “Risk Factors — Proposed Federal TaxChanges”.

(8)                                  Includes changes due to revisedproduction profiles, development timing, operating costs, royalty rates andactual prices received in 2006 versus forecast.

**AdditionalInformation Relating to Reserves Data**

***UndevelopedReserves***

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 willtake longer than two years to develop these reserves.  Penn West plans to develop approximately one—halfof the proved undeveloped reserves in the GLJ Report over the next two yearsand the significant majority of the proved undeveloped reserves over the nextfive years.** **There are a number of factors that could result in delayed orcancelled development, including the following: (i) changing economicconditions (due to pricing, operating and capital expenditure fluctuations);(ii) changing technical conditions (including production anomalies, such aswater breakthrough or accelerated depletion); (iii) multi-zone developments(for instance, a prospective formation completion may be delayed until theinitial completion is no longer economic); (iv) a larger development programmay need to be spread out over several years to optimize capital allocation andfacility utilization; and (v) surface access issues (including those relatingto land owners, weather conditions and regulatory approvals).  For more information, see “Risk Factors”.

***Proved UndevelopedReserves***

GLJ has assigned44 MMboe of proven undeveloped reserves in the GLJ Report under forecastprices and costs, together with $456 million of associated undiscountedfuture capital expenditures.  Provenundeveloped capital spending in the first 

17

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two forecast years of theGLJ Report accounts for $202 million, or 44 percent, of the totalforecast.  These figures increase to $380million or 84 percent, during the first five years of the GLJ Report.  The majority of Penn West’s provenundeveloped reserves evaluated in the GLJ Report are attributable to future oildevelopment from CO2 injection,infill drilling, water injection and miscible fluid injection enhanced oil recovery (“EOR”) projects.

The Pembina Cardium poolis currently developed 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 interestsin 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 the Joffre VikingTertiary Oil Unit and a hydrocarbon injection EOR project in the South SwanHills Unit.  Development of futuremiscible and CO2 injection EOR reserves is scheduled overseveral years in order to maximize the use of existing infrastructure andavailable injectants.

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

***Probable Reserves***

 GLJ has assigned 104 MMboe of ProbableReserves, of which over half (53%) are associated with major properties thatare currently being produced under waterflood, miscible flood and CO2 flood schemes. GLJ has allocated futuredevelopment capital of $351 million to all Probable Reserves with $106 millionscheduled for the first five years. Approximately 20 MMboe or 19% of the totalProbable Reserves are associated with our working interests in three large non-operatedunits.

***SignificantFactors or Uncertainties***

The development scheduleof Penn West’s undeveloped reserves is based on forecast and constant priceassumptions for the determination of economic projects.  The actual prices that occur may besignificantly lower or higher resulting in some projects being delayed oraccelerated, as the case may be.  See “RiskFactors — Volatility of Oil and Natural Gas Prices”.

Penn West does notanticipate that any significant economic factors or other significantuncertainties will affect any particular components of its reserves data.  However, Penn West’s reserves can be affectedsignificantly by fluctuations in product pricing, capital expenditures,operating costs, royalty regimes and well performance that are beyond ourcontrol.

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

Overall costs are basedon well bore abandonment and reclamation costs and liability issues such asflare pit remediation, and facility decommissioning, remediation, andreclamation costs.  These costs wereestimated using Penn West’s experience conducting annual abandonment andreclamation programs over the past several years.

Penn West reviewssuspended or standing well bores for reactivation, recompletion or sale andconducts systematic abandonment programs for those well bores that do not meetour criteria.  A portion of Penn West’sliability issues are retired every year and facilities are decommissioned whenall the wells producing to them have been abandoned.  All of Penn West’s liability reductionprograms take into account seasonal access, high priority and stakeholderissues, and opportunities for multi—location programs to reduce costs.

Penn West’s total inventoryis estimated at 14,578 net well bores and 1,045 facilities as of December 31,2006.  Penn West expects to incurabandonment and reclamation costs in respect to all of these wells, facilitiesand other properties associated with these operations.

The total amount ofabandonment and reclamation costs, net of salvage values, that Penn Westexpects to incur, including wells that extend beyond the 50 year limit in theGLJ Report, are summarized in the following table:

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| **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, 2006 |       | 1,269                                                                                                    |       | 142                                                                                                                     |       |
|                                     |       |                                                                                                     |       |                                                                                                                    |       |
| Anticipated to be paid  in 2007          |       | 37                                                                                                       |       | 34                                                                                                                      |       |
| Anticipated to be paid  in 2008          |       | 38                                                                                                       |       | 31                                                                                                                      |       |
| Anticipated to be paid in 2009           |       | 39                                                                                                       |       | 29                                                                                                                      |       |

The above table includes certain abandonment andreclamation costs, net of salvage values, not included in the GLJ Report andnot deducted in estimating future net revenue as disclosed earlier in thisAnnual Information Form.  Escalated attwo percent and undiscounted, the costs not deducted were $818 million andescalated at two percent and discounted at 10 percent, these costs were$91 million.

**OTHEROIL AND GAS INFORMATION**

Our portfolio ofproperties as at December 31, 2006 includes both unitized and non—unitizedoil and natural gas production.  Ingeneral, the properties contain long-life, low-decline rate reserves andinclude interests in several major oil and gas fields.

***PrincipalProperties***

The following is adescription of our principal oil and natural gas properties as atDecember 31, 2006.  Reserve amountsare stated at December 31, 2006,based on escalated cost and price assumptions as evaluated in the GLJ Reportprepared by GLJ (see “Statement of Reserves Data”).  Information in respect of gross and net acresand well counts is as at December 31, 2006, and information in respect ofproduction is for the year ended December 31, 2006 except where indicatedotherwise.  Due to the fact that we havebeen active at acquiring additional interests in our principal properties, theworking interest share and interest in gross and net acres and wells as atDecember 31, 2006 may not directly correspond to the stated production forthe year, which only includes production since the date the interests wereacquired by us.  In particular,properties producing approximately 40,000 boe/d were acquired under thePetrofund Merger.  The production fromthese properties was recorded effective July 1, 2006.  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 propertiesdescribed below are located in the Western Canadian Sedimentary Basin andwithin the Canadian provinces of British Columbia, Alberta, Saskatchewan orManitoba.  The properties represent 100percent of the total net proved plus probable reserves as assigned by GLJ inthe GLJ Report.** **There are no material propertiesto which reserves have been attributed which are capable of producing but whichare not producing.

***Major OperatingRegions***

The following table showsPenn West’s reported average daily production and Proved plus ProbableReserves, as at December 31, 2006, 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    |       | 36,916                                           |       | 133                                                         |       | 59,142             |       | 190.9 |   | 450.2 |   | 267.1 |   | 1,305 |   |
| Plains     |       | 33,640                                           |       | 95                                                          |       | 49,412             |       | 124.6 |   | 221.5 |   | 162.8 |   | 1,365 |   |
| Northern   |       | 1,934                                            |       | 117                                                         |       | 21,456             |       | 7.1 |   | 289.2 |   | 56.0 |   | 1,045 |   |
| Total      |       | 72,490                                           |       | 345                                                         |       | 130,010            |       | 322.6 |   | 960.9 |   | 485.9 |   | 3,715 |   |
|       |       | 56% of   daily   production                      |       | 44% of   daily

production                                  |       |               |       | 67% of   total   reserves |   | 33% of   total   reserves |   |   |   |   |   |

 

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***Oil and NaturalGas Properties***

Penn West’s productionand reserves are attributed to more than 400 producing properties.  No single property accounts for more than10 percent of Penn West’s reserves. A general discussion of our operations and activities in each of ourcore areas follows.

*NorthernArea*

The Northern Areacurrently provides approximately 34 percent of Penn West’s natural gasproduction and three percent of its liquids production, based on 2006 exit rateproduction.  Geographically, the area encompassesthe land base north of Township 90 in Alberta and extends into the Peace RiverArch and Northeastern regions of British Columbia.  Approximately 43 percent of the NorthernArea’s gas is produced from the Wildboy field in Northeast British Columbia.  Gas is produced from two primary zones inWildboy; the Mississippian at a depth of approximately 600 metres, and the JeanMarie at approximately 1,300 metres. Penn West has net undeveloped land holdings of approximately 1,045,000acres in the Northern Area.

The exploration anddevelopment of the 100 percent owned Wildboy field followed a Penn Westdiscovery in 1995.  Since then,development of the field has continued through the drilling of horizontal andvertical wells, the addition of field booster compression and the subsequentexpansion of the plant process and sales line to Alberta to accommodate theincreased volumes.  Raw throughput of thefacility averaged 69 MMcf/d for 2006.

Penn West drilled 33wells in the Northern Area in 2006, with 2007 plans focusing on additionalfield compression and wellbore optimization in Wildboy, as well as an extensive2D and 3D Mississippian seismic program in Wildboy, in preparation for possibledrilling in the 2008 season.  The PeaceRiver Arch area currently provides approximately four percent of Penn West’stotal production.  In 2006, Penn Westdrilled 15 wells in the Firebird area and two at Buick Creek.  Plans for 2007 are focused on wellboreoptimization at Firebird, Spirit River and Cecil Lake, with current plans for2008 to drill 18 locations in Firebird. Penn West currently holds approximately 74,000 net acres of undevelopedland in the Peace River Arch area.

*CentralArea*

The Central Areacurrently provides approximately 39 percent of Penn West’s natural gasproduction and 51 percent of its liquids production based on 2006 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 production growth.  Penn West’s long-life, low decline rateCardium oil reserves in the Central Area provide a stable source of premiumquality light oil.  Cardium oil receivesa price very close to the Edmonton par price. Penn West holds approximately 1,305,000 net acres of undeveloped land inthe Central Area.

The Central Area is alsoa significant natural gas producing area, with production of 133 MMcf/d atyear-end 2006.  The natural gas prospectsin 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 hasgrown its land base to approximately 300,000 net acres of 100 percent owned oilsands leases in the Peace River oil sands area.  As of the end of 2006, we have drilled 54horizontal wells and seven stratigraphic wells in the focus areas of Seal Main,Seal North and Cadotte.  In 2006, PennWest acquired a 35 percent working interest in a 13,500 bbl/d facility anda 15 percent working interest in a 55,000 bbl/d pipeline.  In 2007, 30 stratigraphic wells and 80 to 90net horizontal wells are planned, with capital programs of approximately $175million, excluding acquisitions.  PennWest currently estimates the project area contains 6.8 billion barrels ofheavy oil resources in place.  Thisestimate represents the mid case.  Usingthe definitions set out in the COGE Handbook, these resources are considered “DiscoveredResources”.  As Penn West is in the earlystages of the project, these resources have not been classified into morespecific categories.  There is nocertainty that a significant portion of these resources will be recovered orthat a significant portion of the resources will be economically or technicallyfeasible to produce in the future. Discovered resources are those quantities of oil and gas estimated on agiven date to be remaining in, plus those quantities already produced from,known accumulations.  Discovered

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resources consist ofeconomic and uneconomic resources with the estimated future recoverable portionclassified as reserves or contingent resources.

*Central-Pembina*

Pembina produceshigh-netback, long-life, low-decline light oil and liquids-rich naturalgas.  Approximately 1,150 operatedproducing wellbores account for 14,400 bbl/d or 11 percent of our 2006production.  The Petrofund Merger furtherconsolidated Penn West’s land position in the area, lifting our average workinginterest to approximately 87 percent and increasing overall operatedvolumes by about 20 percent or approximately 2,900 boe/d.  Our share of current Pembina area productionis approximately 18,900 boe/d including operated and non-operated volumes.

The group of propertiesis centred on the extensive, long-life Cardium oil pool.  The pool’s secondary recovery (water flood)phase is currently being optimized while our EOR team prepares the plans toexpand the CO2 flood to other areas.

The Pembina field team’soverall focus is on low-risk drilling and low-cost optimization opportunitiesthat are aimed at maximizing distributions to the Trust’s Unitholders andreinvestment capital for Penn West’s long-term resource plays.  Costs are kept down to increase netbacks byexploiting Penn West’s large network of operated infrastructure, which includesseven gas plants, numerous oil batteries and over 3,000 kilometres of oil andgas gathering lines.

The Pembina Cardium poolis relatively lightly-drilled with many opportunities for conventionalexploration and development of shallow through deep targets.  Pembina has an array of multizone potentialthroughout the area, including the Edmonton Sands, Belly River, Cardium,Glauconite, Ellerslie, Rock Creek, Pekisko, Banff and some deep Swan Hills.

Penn West drilled 18gross wells in 2006, with plans for a 2007 drilling program of 17 wells.  This drilling program is a mix of low-riskcardium infill wells, development wells and a deep gas well.  As in 2006, Penn West continues to strive toimprove efficiency of operations to maximize oil and gas recovery through theuse of geological and reservoir studies and enhanced recovery methods.

*Central- Willesden Green*

Located south of Pembina,Willesden Green is an area of long-life and low-decline light oil andliquids-rich natural gas from multiple zones. Control of key infrastructure improves our returns by providing us withoperational control.

Willesden Green is anactive development area.  The 17development and exploitation wells planned in 2007 (up from 10 wells in2006) are intended to fully offset natural production declines.  We retain deep mineral rights throughout thearea, enhancing longer-term exploration potential for Penn West or drillingpartners.

Over the past two years,the production from the Willesden Green area has remained relatively constantthrough oil and gas well drilling and optimization of the area’s wells andinfrastructure.  In addition, the areahas one of our highest netbacks due to its mix of light oil, liquids richnatural gas, low royalty rates and relatively low net operating costs.  Penn West controls the area’s oil and naturalgas gathering infrastructure that is centred on our 100 percent-ownedWillesden Green gas plant. In 2006, Penn West de-bottlenecked its gas gatheringand gas processing infrastructure, increasing the plant’s capacity to processadditional Penn West and third-party volumes.

In 2006, seven infillwells were drilled focusing on the 100 percent working interest Cardiumoil and Belly River natural gas pools. For 2007, we will drill eight wells, and will pursue a multi-yearprogram to downspace the Cardium from one well per 80-160 acres to oneper 40 acres.

*Central— Swan Hills*

Penn West holds amajority interest in the South Swan Hills Unit, as well as other interests inthe area.  South Swan Hills is a lightoil pool where a combination of water and miscible hydrocarbon injection isused to increase recovery factors.

The South Swan Hills Unitis also the site of two new pilot projects: The Mannville horizontal coal bedmethane (“CBM”) project, which is currently beginning production operations andthe Swan Hills CO2 pilot, which is scheduled to beginconstruction later in 2007.

The CBM pilot was drilledin late 2006 and has been on production since early 2007.  The pilot wells are currently in the processof dewatering the wells before gas production can occur.  Based on production experience at theoffsetting successful

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Trident/Nexen’s CorbettCreek CBM property, the dewatering process could take between six and12 months for the initial pilot wells, shortening as development takesplace and the coals are de-pressured. Pending the success of the pilot project, full-scale CBM developmentcould take place over the next four years.

The planned CO2 pilot in South Swan Hills will target portionsof the Swan Hills reef complex that have not been efficiently miscible floodedin the past.  This pilot will also helpin 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.

The Petrofund Merger in2006 also resulted in new or increased working interests in the Swan Hills Unit#1, House Mountain Unit, Mitsue Unit, and the Kaybob Unit.  Additional working interests were acquired inthe Otter and Red Earth areas with new production in the Loon and Ogston areasalso acquired.

*PlainsArea*

The Plains Area is ashallow depth region with multi-zone potential that supplies 28 percent of PennWest’s natural gas production and 46 percent of the liquids based on 2006 exitrate production.  In 2006, Penn Westdrilled 148 net wells in this area. Target zones include the Bakken, Mannville and Viking.  Extensive 2D and 3D seismic is used to selectdrilling locations.  Penn West owns andoperates an extensive infrastructure of gas plants, batteries and pipelines inthe Plains Area.  In 2007, Penn Westplans to drill 95 net wells and holds approximately 1,365,000 net acres ofundeveloped land in the area.

*Plains— Wainright*

Key characteristics ofthe Wainright property group include: extensive developed and undevelopedlands, high working interests, low-decline heavy oil and Viking natural gasproduction, and widespread infrastructure. These advantages allow Penn West to continually optimize operations whileadding new production at low risk and cost throughout the area.

In 2006, investment of$17 million funded 200 separate optimization projects.  Development drilling added 640 bbl/d in newvolumes.  Complemented by properties atSugden, Consort, and Ribstone acquired with the Petrofund Merger, the  Wainwright group of properties generatedoverall volumes of 9,300 bbl/d or approximately seven percent of the Trust’s 2006exit production.

*Plains— Hoosier — Coleville*

Hoosier and Coleville consistof more than 20 producing properties around Hoosier and form one of Penn West’smost active development areas.  Thesemostly Penn West operated assets include approximately 4,210 producingwellbores, a high average working interest of over 95 percent, extensive PennWest infrastructure and a combined 918,000 acres of lands, of which 396,000 netacres are undeveloped.  The PetrofundMerger added geographically and technically complementary properties to theHoosier group, increasing the area’s production by 10 percent.

Hoosier’s primarycommodity is cold-pumped conventional heavy oil.  The main geological targets are theseismically defined Mannville Group, Bakken and geographically vast Vikinghorizons, all at depths shallower than 850 metres.  Penn West drilled 97 wells throughoutHoosier in 2006, including 34 vertical wells, 16 horizontal wells and47 natural gas wells.  The programadded 1,550 bbl/d of crude oil and four MMcf/d of natural gas withadditional new capacity “behind pipe” to be tied in during 2007.

In 2007, Penn West hasbudgeted $47 million to drill 51 vertical wells and eight horizontal wells inHoosier.  The main focus will be oildevelopment driven by the scope of medium-term opportunities rather than short-termprice volatility.

*Plains— South and Other Area*

The Plains South Area isa proven producing region with long-life light oil reserves from a variety ofstratigraphic zones producing a total of approximately 17,200 bbl/d.  These properties stretch from the Rocky Mountainsto western Manitoba and 200 kilometres north from the U.S. border.  This large geographic region includes manyopportunities for development and optimization.

We acquired a 21.1percent interest in the Weyburn Unit located in Southeast Saskatchewan in thePetrofund Merger.  Weyburn is Canada’slargest commercial CO2 enhanced oil recovery project, producingapproximately 30,000 bbl/d (approximately 6,300 bbl/d net to us) at December31, 2006, sourcing CO2 for injection from a coal gasification plantin North Dakota.  Our share of capitalcosts was $43.2 million in 2006 increasing to approximately $44.8 million in2007 due to

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increases to the rate ofCO2 injection and the drilling of additionalwells.  The application of CO2 miscible flooding increased the estimated 30percent oil recovery rate under water flooding to an estimated 46 percent underCO2 enhanced recovery.  With the Petrofund Merger, we also increasedour working interest in the Midale Unit to approximately 8.7 percent where CO2 flooding will occur using the same CO2 source as Weyburn.

*AdditionalInformation*

None of Penn West’simportant properties, plants, facilities or installations are subject to anymaterial statutory or other mandatory relinquishments, surrenders, back-insor changes in ownership.

For a discussion ofproperties to which reserves have been attributed and which are capable ofproducing but which are not producing, see “Statement of Reserves Data -Additional Information Relating to Reserves Data — Undeveloped Reserves”.

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***Oil And Gas Wells***

The following table setsforth the number and status of wells in which we had a working interest as atDecember 31, 2006.
| ** **       | ** ** | **Producing** | ** ** | **Non-Producing** | ** ** | **Total**  | ** ** |
|------------------|------------|---------------|------------|-------------------|------------|------------|------------|
| ** **       | ** ** | **Oil**       | ** ** | **Gas**           | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **       | ** ** | **Gross**     | ** ** | **Net**           | ** ** | **Gross**  | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Alberta          |       | 6,122         |       | 4,065             |       | 3,280      |       | 2,117 |   | 4,135 |   | 2,837 |   | 13,537 |   | 9,019 |   |
| British Columbia |       | 48            |       | 20                |       | 468        |       | 304 |   | 200 |   | 136 |   | 716 |   | 460 |   |
| Saskatchewan     |       | 3,640         |       | 3,019             |       | 661        |       | 536 |   | 1,713 |   | 1,344 |   | 6,014 |   | 4,899 |   |
| Manitoba         |       | 137           |       | 129               |       | —     |       | — |   | 76 |   | 71 |   | 213 |   | 200 |   |
| Total            |       | 9,947         |       | 7,233             |       | 4,409      |       | 2,957 |   | 6,124 |   | 4,388 |   | 20,480 |   | 14,578 |   |

***Undeveloped Land Holdings***

The following table setsout our undeveloped land holdings as at December 31, 2006.

|                  | ** ** | **Undeveloped Acres (000s)** | ** ** |
|------------------|------------|----------------------------------------|------------|
| ** **       | ** ** | **Gross**                              | ** ** | **Net** | ** ** |
| Alberta          |       | 2,715                                  |       | 2,422 |   |
| British Columbia |       | 625                                    |       | 497 |   |
| Saskatchewan     |       | 693                                    |       | 654 |   |
| Manitoba         |       | 143                                    |       | 142 |   |
| Total            |       | 4,176                                  |       | 3,715 |   |

We currently have no material work commitments onthese lands.  The primary lease orextension term on 1,030,000 net acres will expire by December 31,2007.  The right to explore, develop andexploit these leases will be surrendered unless we qualify them forcontinuation based on existing production, drilling or technical mapping.

***Tax Horizon***

Under currently enactedlegislation, as a result of our tax structure, taxable income is transferredfrom our operating entities to the Trust and from the Trust toUnitholders.  This is primarilyaccomplished through the deduction by our operating entities of the royaltieson underlying oil and gas properties and the deduction of interest on theNotes.  The terms of the Trust Indenturerequire the Trust to distribute all of its taxable income, therefore, it iscurrently expected that no income tax liability will be incurred provided wemaintain this organizational structure. To the extent that taxable income is retained in our operating entitiesto fund capital expenditures or repay bank debt, it is possible that incometaxes could be payable at some time in the future. If the proposed changes tothe taxation of income trusts are enacted, taxes could be exigible in the Trustas certain distributions would no longer be a deduction in the calculation ofits taxable income.  For more informationon these proposals, see “Description of Our Business — Proposed Federal TaxChanges” and “Risk Factors — Proposed Federal Tax Changes”.

***CapitalExpenditures***

The following tablesummarizes capital expenditures (net of incentives and net of certain proceeds)related to our activities for the year ended December 31, 2006:

24

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|                         | ** ** | **2006  MM$** | ** ** | **2005  MM$** | ** ** |
|-------------------------|------------|---------------|------------|---------------|------------|
| Property Acquisitions   |       |          |       |          |       |
| Proved  Properties      |       | $             | 5.6        |          | $          | (5.8 | ) |
| Undeveloped  Properties |       | 19.8          |       | 13.5          |       |
| Exploration Costs(1)    |       | 82.9          |       | 140.4         |       |
| Development Costs(2)    |       | 462.7         |       | 299.3         |       |
| Corporate Costs         |       | 6.9           |       | 9.3           |       |
| Capital Expenditures    |       | 577.9         |       | 456.7         |       |
| Petrofund Merger        |       | 3,323.3       |       | —        |       |
| Total Expenditures      |       | $             | 3,901.2    |          | $          | 456.7 |   |

----

Notes:

(1)             Costs of landacquired, geological and geophysical capital expenditures and drilling costsfor 2006 exploration wells drilled.

(2)             Includesequipping and facilities capital expenditures.

***Exploration andDevelopment Activities***

The following table setsforth the gross and net exploratory and development wells that we participatedin during the year ended December 31, 2006:

|             | ** ** | **Exploratory Wells** | ** ** | **Development Wells** | ** ** |
|-------------|------------|----------------------------|------------|----------------------------|------------|
| ** **  | ** ** | **Gross**                  | ** ** | **Net**                    | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Oil         |       | 27                         |       | 26                         |       | 166 |   | 123 |   |
| Natural Gas |       | 46                         |       | 40                         |       | 135 |   | 65 |   |
| Dry         |       | 2                          |       | 2                          |       | 15 |   | 14 |   |
| Total       |       | 75                         |       | 68                         |       | 316 |   | 202 |   |

We initially estimated capital expenditures of$550 million to $650 million in 2007 to execute our capital programs.The primary components of our program are described under the heading “OtherOil and Gas information — Oil and Natural Gas Properties”.  Subsequent to the completion of our 2007budget, our Board of Directors approved the $339 million property acquisitionannounced in February 2007 and an increase to the budgeted capital programin the Peace River Oil Sands Project to $175 million from$100 million.

***ProductionEstimates***

The following table setsout the volume of our production estimated for the year ended December 31,2007 which is reflected in the estimate of future net revenue disclosed in thetables contained under “Statement of Reserves Data - Disclosure ofReserves Data”.
| ** **                      | ** ** | **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                |       | 39,000                              |       | 34,168             |       | 19,749               |       | 17,544                        |       | 295,371     |       | 233,485 |   | 5,962 |   | 4,164 |   | 113,939 |   | 94,789 |   |
| Proved Developed  Non-Producing |       | 616                                 |       | 500                |       | 407                  |       | 340                           |       | 13,888      |       | 10,546 |   | 213 |   | 148 |   | 3,551 |   | 2,746 |   |
| Proved Undeveloped              |       | 1,323                               |       | 1,042              |       | 382                  |       | 293                           |       | 1,672       |       | 1,305 |   | 72 |   | 52 |   | 2,056 |   | 1,604 |   |
| Total Proved                    |       | 40,939                              |       | 35,710             |       | 20,538               |       | 18,177                        |       | 310,931     |       | 245,336 |   | 6,247 |   | 4,364 |   | 119,546 |   | 99,139 |   |
| Total Probable                  |       | 807                                 |       | 563                |       | 893                  |       | 171                           |       | 16,561      |       | 12,401 |   | 197 |   | 140 |   | 4,656 |   | 3,487 |   |
| Total Proved PlusProbable       |       | 41,746                              |       | 36,273             |       | 21,431               |       | 18,894                        |       | 327,492     |       | 257,737 |   | 6,444 |   | 4,504 |   | 124,202 |   | 102,626 |   |

 

25

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***Production History***

The following tablessummarize certain information in respect of our production, product pricesreceived, royalties paid, operating expenses and resulting netback for theperiods indicated below:
| ** **                                | ** ** | **Quarter Ended 2006** | ** ** | **Year Ended** | ** ** |
|-------------------------------------------|------------|----------------------------------|------------|---------------------|------------|
| ** **                                | ** ** | **Mar. 31**                 | ** ** | **June 30**    | ** ** | **Sept. 30** | ** ** | **Dec. 31** | ** ** | **Dec. 31, 2006** | ** ** |
| Average Daily  Production(1)              |       |                             |       |                |       |   |   |   |   |   |   |
| Light and Medium  Crude Oil (bbl/d)       |       | 27,441                           |       | 26,646              |       | 42,150 |   | 42,898 |   | 34,847 |   |
| Heavy Oil  (bbl/d)                        |       | 20,685                           |       | 18,625              |       | 21,186 |   | 22,586 |   | 20,776 |   |
| Gas (MMcf/d)                              |       | 266.9                            |       | 267.9               |       | 359.1 |   | 354.6 |   | 312.5 |   |
| NGLs (bbl/d)                              |       | 4,100                            |       | 3,331               |       | 5,879 |   | 5,335 |   | 4,668 |   |
| Combined (boe/d)                          |       | 96,713                           |       | 93,242              |       | 129,059 |   | 129,915 |   | 112,369 |   |
|                                      |       |                             |       |                |       |   |   |   |   |   |   |
| Average Net Production  Prices Received   |       |                             |       |                |       |   |   |   |   |   |   |
| Light and Medium  Crude Oil ($/bbl)       |       | 63.42                            |       | 73.20               |       | 72.27 |   | 58.51 |   | 66.46 |   |
| Heavy Oil  ($/bbl)                        |       | 30.76                            |       | 52.85               |       | 52.20 |   | 37.57 |   | 43.07 |   |
| Gas ($/Mcf)                               |       | 8.12                             |       | 6.14                |       | 5.97 |   | 6.97 |   | 6.75 |   |
| NGLs ($/bbl)                              |       | 53.19                            |       | 62.08               |       | 55.75 |   | 48.76 |   | 54.31 |   |
| Combined ($/boe)                          |       | 49.23                            |       | 51.33               |       | 51.33 |   | 46.88 |   | 49.58 |   |
|                                      |       |                             |       |                |       |   |   |   |   |   |   |
| Royalties Paid                            |       |                             |       |                |       |   |   |   |   |   |   |
| Light and Medium  Crude Oil ($/bbl)       |       | 9.36                             |       | 8.83                |       | 10.40 |   | 9.38 |   | 9.58 |   |
| Heavy Oil  ($/bbl)                        |       | 4.85                             |       | 8.50                |       | 7.50 |   | 5.44 |   | 6.51 |   |
| Gas ($/Mcf)                               |       | 1.78                             |       | 1.43                |       | 1.28 |   | 1.61 |   | 1.51 |   |
| NGLs ($/bbl)                              |       | 17.58                            |       | 21.05               |       | 15.87 |   | 16.91 |   | 17.46 |   |
| Combined ($/boe)                          |       | 9.36                             |       | 9.09                |       | 8.90 |   | 9.12 |   | 9.10 |   |
|                                      |       |                             |       |                |       |   |   |   |   |   |   |
| Operating Expenses  (2)(3)                |       |                             |       |                |       |   |   |   |   |   |   |
| Light and Medium  Crude Oil ($/bbl)       |       | 15.64                            |       | 16.38               |       | 16.57 |   | 15.53 |   | 16.03 |   |
| Heavy Oil  ($/bbl)                        |       | 10.55                            |       | 11.49               |       | 10.93 |   | 11.88 |   | 11.22 |   |
| Gas ($/Mcf)                               |       | 0.94                             |       | 0.97                |       | 1.00 |   | 1.04 |   | 0.99 |   |
| NGLs ($/bbl)                              |       | 13.87                            |       | 13.85               |       | 14.43 |   | 13.98 |   | 14.09 |   |
| Combined ($/boe)                          |       | 9.88                             |       | 10.26               |       | 10.64 |   | 10.61 |   | 10.39 |   |
|                                      |       |                             |       |                |       |   |   |   |   |   |   |
| Transportation                            |       |                             |       |                |       |   |   |   |   |   |   |
| Light and Medium  Crude Oil ($/bbl)       |       | —                           |       | —              |       | — |   | — |   | — |   |
| Heavy Oil  ($/bbl)                        |       | 0.15                             |       | —              |       | 0.07 |   | 0.07 |   | 0.07 |   |
| Gas ($/Mcf)                               |       | 0.23                             |       | 0.21                |       | 0.23 |   | 0.18 |   | 0.21 |   |
| NGLs ($/bbl)                              |       | —                           |       | —              |       | — |   | — |   | — |   |
| Combined ($/boe)                          |       | 0.66                             |       | 0.60                |       | 0.64 |   | 0.51 |   | 0.60 |   |
|                                      |       |                             |       |                |       |   |   |   |   |   |   |
| (Gain)/Loss on Risk  Management Contracts |       |                             |       |                |       |   |   |   |   |   |   |
| Light and Medium  Crude Oil ($/bbl)       |       | —                           |       | 2.37                |       | 2.24 |   | 0.01 |   | 1.14 |   |
| Heavy Oil  ($/bbl)                        |       | —                           |       | —              |       | — |   | — |   | — |   |
| Gas ($/Mcf)                               |       | (0.22)                           |       | (0.93)              |       | (1.07) |   | (0.56) |   | (0.72) |   |
| NGLs ($/bbl)                              |       | —                           |       | —              |       | — |   | — |   | — |   |
| Combined ($/boe)                          |       | (0.62)                           |       | (2.00)              |       | (2.23) |   | (1.53) |   | (1.64) |   |
|                                      |       |                             |       |                |       |   |   |   |   |   |   |
| Netback Received(4)                       |       |                             |       |                |       |   |   |   |   |   |   |
| Light and Medium  Crude Oil ($/bbl)       |       | 38.41                            |       | 45.60               |       | 43.05 |   | 33.58 |   | 39.70 |   |
| Heavy Oil  ($/bbl)                        |       | 15.21                            |       | 32.86               |       | 33.70 |   | 20.18 |   | 25.27 |   |
| Gas ($/Mcf)                               |       | 5.39                             |       | 4.46                |       | 4.53 |   | 4.70 |   | 4.76 |   |
| NGLs ($/bbl)                              |       | 21.74                            |       | 27.18               |       | 25.40 |   | 17.87 |   | 22.75 |   |
| Combined ($/boe)                          |       | 29.95                            |       | 33.38               |       | 33.38 |   | 28.17 |   | 31.13 |   |

----

Notes:

(1)                                  Before deduction of royalties.

(2)                                  Operating expenses are composed of directcosts 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 recoveries associated withoperated properties are charged to operating costs and accounted for as areduction to general and administrative costs.

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(4)                                  Netbacks are calculated by subtractingroyalties, operating costs, transportation and losses/gains on commodity andforeign exchange contracts from revenues.

No property accounts formore than nine percent of the production disclosed above.  For more information, see “Other Oil and GasInformation — Principal Properties”.

**Marketing and Future Commitments**

Our marketing approachcontinues to reflect the following principles:

·                  Maximize production from existingassets and avoid any shut-in production due to marketing constraints.

·                  Diversify natural gas pricing on ageographic basis in order to maintain competitive prices.

·                  Optimizenetbacks on crude oil production through blending, trucking and proprietaryhandling of emulsion.

***Natural Gas Marketing***

In 2006, Penn Westreceived an average price from the sale of natural gas, including hedginggains, of $7.47/Mcf compared to $8.74/Mcf realized in 2005.  Approximately 85 percent of our natural gassales are marketed directly with the balance of natural gas sales marketed inaggregator pools.  We continue tomaintain a significant weighting to the Alberta market as this market offers apremium netback relative to most other indices. In addition to maximizing netbacks, the current portfolio approach alsoenhances our operational flexibility to pursue higher netback opportunities asthey become available.

We continue toconservatively manage our transportation costs. Transportation on all pipelines is closely balanced to supply, andmarket commitments related to export transportation represented less than fivepercent of sales.

***Oil and LiquidsMarketing***

The average quality ofour crude oil production is 28o API. Approximately 61 percent of ourliquids production can be attributed to light and medium oil, with an averageAPI of 36o.Conventional heavy oil, at 15o average API, comprises approximately 33percent of total liquids production. Production of NGLs account for approximately six percent of totalliquids production.

We market our productionat the lease level on varying term contracts that capture premiums on postingsfor the majority of corporate sales and actively manage our heavy oil supply byfinding opportunities to optimize netbacks through blending, trucking andproprietary handling of emulsion. Blending costs are also controlled throughthe use of proprietary condensate supply.

The following tablesummarizes the net product price received for our production of conventionallight and medium oil and conventional heavy oil for the periods indicated:
| ** **             | ** ** | **2006**                                | ** ** | **2005**           | ** ** |
|------------------------|------------|-----------------------------------------|------------|--------------------|------------|
| ** **             | ** ** | **Light and Medium Oil** | ** ** | **Heavy Oil** | ** ** | **Light and Medium Oil** | ** ** | **Heavy Oil** | ** ** |
| **Quarter ended** | ** ** | **($/bbl)**                             | ** ** | **($/bbl)**        | ** ** | **($/bbl)** | ** ** | **($/bbl)** | ** ** |
| March 31               |       | 63.42                                   |       | 30.76              |       | 57.62 |   | 28.06 |   |
| June 30                |       | 73.20                                   |       | 52.85              |       | 61.01 |   | 31.22 |   |
| September 30           |       | 72.27                                   |       | 52.20              |       | 73.76 |   | 48.60 |   |
| December 31            |       | 58.51                                   |       | 37.57              |       | 64.56 |   | 34.95 |   |

***Forward Contracts***

Our Board of Directorsapproved a policy that enables us to hedge up to 50 percent of our liquidsand natural gas price exposure (net of royalties) for a maximum of two yearsand up to 75 percent for a maximum of one year.  As at December 31, 2006 Penn West was notbound by any agreement (including a transportation agreement), directly orthrough an aggregator, under which it may be precluded from fully realizing, orfrom being protected from the full effect of, future market prices for oil ornatural gas except for the following financial hedging positions that wereoutstanding as at December 31, 2006:

27

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| ** **                | ** ** | **Notional Volume** | ** **    | **Remaining Term** | ** **    | **Pricing**          | ** **      | **Market Value(1)  (MM$)** | ** ** |
|---------------------------|------------|--------------------------|---------------|-------------------------|---------------|----------------------|-----------------|---------------------------------|------------|
| **Crude Oil**             |       |                     |          |                    |          |                 |            |                            |       |
| WTI Costless  Collars     |       | 3,000 bbl/d              |          | Jan/-Mar/07             |          | US$56.67-$84.28  bbl |            | 0.2                             |       |
| WTI Costless  Collars     |       | 1,000 bbl/d              |          | Jan/-Jun/07             |          | US$60.00-$73.10  bbl |            | 0.2                             |       |
| WTI Costless  Collars     |       | 1,000 bbl/d              |          | Apr/-Jun/07             |          | US$60.00-$80.00  bbl |            | 0.2                             |       |
| WTI Costless  Collars     |       | 25,000 bbl/d             |          | Jan/-Dec/07             |          | US$56.00-$83.80  bbl |            | 7.9                             |       |
| WTI Costless  Collars     |       | 10,000 bbl/d             |          | Jan/-Jun/08             |          | US$60.00-$94.55  bbl |            | 6.2                             |       |
| **Natural Gas**           |       |                     |          |                    |          |                 |            |                            |       |
| AECO Costless Collars     |       | 9,200 Mcf/d              |          | Jan/-Mar/07             |          | $                    | 9.18-$12.97/Mcf |                            | 1.0        |   |
| AECO Costless Collars     |       | 73,400 Mcf/d             |          | Jan/-Oct/07             |          | $                    | 7.63-$9.68/Mcf  |                            | 20.8       |   |
| **Electricity**           |       |                     |          |                    |          |                 |            |                            |       |
| Alberta Power  Pool Swaps |       | 67 MW                    |          | 2007                    |          | $                    | 49.50 MWH       |                            | 17.3       |   |
| Alberta Power  Pool Swaps |       | 2 MW                     |          | 2008                    |          | $                    | 57.00 MWH       |                            | 0.4        |   |
| **Interest Rate Swaps**   |       | $                        | 100.0 million |                    | Jan/07-Mar/08 |                 | 4.356           | %                               | (0.2       | ) |
| ** **                |       |                     |          |                    |          |                 |            | 54.0                            |       |
|                           |            |                          |               |                         |               |                      |                 |                                 |            |  |  |

----

Note:

(1)                                  Unrealized gain (loss) based oncalculations using posted rates for similar contracts on December 31, 2006.

Our transportationobligations and commitments for future physical deliveries of crude oil andnatural gas do not exceed our expected related future production from ourproved reserves, estimated using forecast prices and costs.

***Future Commitments***

We have committed tocertain payments over the next five years, in addition to regular paymentsunder our credit facilities, as follows:
| **($ millions)**   | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** | **Thereafter** | ** ** |
|-------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------|------------|
| Transportation          |       | 20.0     |       | 9.2      |       | 4.7      |       | 1.9      |       | —   |       | —         |       |
| Transportation ($US)    |       | 2.5      |       | 2.3      |       | 2.3      |       | 2.3      |       | 2.3      |       | 8.6            |       |
| Power Infrastructure    |       | 4.6      |       | 3.7      |       | 3.7      |       | 3.7      |       | 3.7      |       | 7.6            |       |
| Drilling Rigs           |       | 6.9      |       | 7.7      |       | 2.4      |       | 1.2      |       | —   |       | —         |       |
| Purchase Obligations(1) |       | 13.2     |       | 13.3     |       | 13.3     |       | 13.3     |       | 13.3     |       | 54.3           |       |
| Office Lease            |       | 12.0     |       | 17.9     |       | 17.5     |       | 15.1     |       | 14.3     |       | 117.5          |       |

----

Note:

(1)                                  These amounts represent estimatedcommitments of $95.5 million for CO2 purchases and $25.2 million for processingfees related to interests in the Weyburn unit.

**Environmental Matters**

The oil and natural gasindustry is subject to environmental regulations under provincial and federallegislation. Environmental regulations impose, among other things,restrictions, liabilities and obligations in connection with the generation,handling, storage, transportation, treatment and disposal of hazardoussubstances and waste and in connection with spills, releases and emissions ofvarious substances to the environment. Environmental legislation also requiresthat wells, facility sites and other properties associated with our operationsbe operated, maintained, abandoned and reclaimed to the satisfaction ofapplicable regulatory authorities. In addition, certain types of operations,including exploration and development projects and significant changes tocertain existing projects, may require the submission and approval ofenvironmental impact assessments or permit applications. Compliance with thislegislation can require significant expenditures; a breach of such requirementscould result in the imposition of material fines and facility closures. PennWest’s environmental programs are monitored to ensure that they comply with allgovernment environmental regulations and with Penn West’s own environmental policies.The results of these programs are reviewed with Penn West’s management andoperations personnel.

In December 2002, theGovernment of Canada ratified the Kyoto Protocol that became legally binding onFebruary 16, 2005. This protocol calls for Canada to reduce its greenhousegas emissions to six percent below 1990 levels during the period between 2008and 2012. Details of specific requirements relating to the oil and gas industryhave not been enacted and accordingly the impact of the Kyoto Protocol isunknown.

28

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The Government ofCanada has announced its intention to regulate greenhouse gases (GHG) and otherair pollutants. The Government is currently developing a framework thatoutlines its clean air and climate change action plan, including a target toreduce GHG emissions by 45 percent to 65 percent by 2050 and a commitment toregulate industry on an emissions intensity basis in the short-term. Currentlythere are few technical details regarding the implementation of the Government’splan to regulate industrial GHG emissions, but the Government has made acommitment to work with industry to develop the specifics.

The AlbertaGovernment has also released draft regulations that will require facilitiesthat emit over 100,000 tonnes of CO2E/yr (total Greenhouse Gases in terms ofCO2 equivalent) to reduce their emissionsintensity (quantity of gases releases per unit of production) by12 percent starting July 1, 2007. Facilities that do not reduce their emissions intensity by this amountwill either be charged $15/tonne for every tonne they emit in excess of the12 percent target or they will have to invest in projects outside of theirfacility, but still in Alberta, that reduce or offset emissions on theirbehalf.  Penn West currently does notoperate any facilities that fall under the current regulations but it does havea working interest in some facilities that do. The full impact of this regulation is currently unknown but it is verylikely that these targets will result in increased operating costs forfacilities that are under these regulations. However, Penn West believes that this new regulation will be of overallbenefit to the Trust as it will most likely result in increased interest in CO2 capture and storage technologies andinfrastructure that will increase the speed of development of its CO2 injection plans in Pembina.

As the federal andprovincial programs are under development, Penn West is unable to predict thetotal impact of the potential regulations upon its business. Therefore, it ispossible that we could face increases in operating costs in order to complywith GHG emissions legislation. However, Penn West in cooperation with theCanadian Association of Petroleum Producers will continue to work with theGovernment to develop an approach to deal with climate change issues thatprotects the industry’s competitiveness, limits the cost and administrativeburden of compliance and supports continued investment in the sector.  In the meantime, we will continue our currentactivities to reduce emissions intensity, improve energy efficiency and developCO2 injection and sequestrationinfrastructure.  See “Risk Factors —Environmental” and “Risk Factors — Kyoto Protocol”.

We fullyunderstand our responsibilities of reducing the environmental impacts from our oiland recognize the interests of other land users in resource development areas,and conduct our operations accordingly. We are committed to reducing the environmental impact from oil andnatural gas operations, and to involving stakeholders throughout theexploration, development, production and abandonment process. Our environmentalprograms encompass resource conservation, stakeholder communication, carbondioxide sequestration and site abandonment/reclamation.

Our EnvironmentalPolicy and Environmental Management Plan (“EMP”) encompass the full range ofair, water, soil and waste issues associated with exploration, development andproduction. The EMP includes guidelines to 11 key areas that are considered inconjunction with oil and natural gas development plans. These guidelines helpensure safe and environmentally sound field operations. The EnvironmentalOperating Guidelines are used to train our employees in the practical andeconomical implementation of the EMP.

We maintain aprogram of detailed inspections, audits and field assessments to determine andquantify the environmental liabilities that will be incurred during theeventual decommissioning and reclamation of our field facilities. Penn Westpursues a program of environmental impact reduction aimed at minimizing thesefuture corporate liabilities without hampering field productivity. Thisprogram, launched in 1994 and ongoing into 2007, includes measures to remediatepotential contaminant sources, reclaim spill sites and abandon unproductive wellsand shut-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” carbon dioxide inhydrocarbon reservoirs.

During 2006, wecontinued our pilot-scale carbon dioxide injection program at Pembina, withinjection of carbon dioxide commencing in February 2005. To date, in excess ofone billion cubic feet of carbon dioxide has been injected. If successful, thepilot could lead to a much larger enhanced oil recovery program with potentialto sequester very significant volumes of carbon dioxide. Also in 2006, wecontinued to participate in studies to develop a cost effective system tosource large volumes of carbon dioxide currently emitted within Alberta, and totransport it by pipeline for injection into producing oil fields in centralAlberta.  See “Risk Factors — ResourcesPlays — Enhanced Oil Recovery”.

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**CAPITALIZATION OF PENN WESTPETROLEUM LTD.**

**Common Shares**

Penn WestPetroleum Ltd. 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 Penn West Petroleum Ltd. with any other entity, except in conjunction withan internal reorganization as referred to in paragraph (i) above; (iii) anystatutory arrangement involving Penn West Petroleum Ltd., except in conjunctionwith an internal reorganization as referred to in paragraph (i) above; (iv) anyamendment to the articles of Penn West Petroleum Ltd. to increase or decreasethe minimum or maximum number of directors; or (v) any material amendment tothe articles of Penn West Petroleum Ltd. to change the authorized share capitalor amend the rights, privileges, restrictions and conditions attaching to anyclass of Penn West Petroleum Ltd.’s shares in a manner which may be prejudicialto us, without the approval of the Unitholders by special resolution at ameeting of Unitholders called for that purpose.

The holders ofcommon shares are entitled to receive notice of and to attend all meetings ofthe shareholders of Penn West Petroleum Ltd. 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 Penn West Petroleum Ltd.upon the liquidation, dissolution, bankruptcy or winding-up of Penn WestPetroleum Ltd. or other distribution of its assets among its shareholders forthe purpose of winding-up its affairs subject to the rights, privileges,restrictions and conditions attaching to any other shares having priority overthe common shares.

**Preferred Shares**

Penn WestPetroleum Ltd. is authorized to issue an unlimited number of Preferred Sharesin series.  Before any shares of aparticular series are issued, the Board of Directors shall, by resolution, fixthe number of shares that will form such series and shall, subject to thelimitations set out herein, by resolution fix the designation, rights,privileges, restrictions and conditions to be attached to the Preferred Sharesof such series.  The Preferred Shares ofeach series shall rank on a parity with the Preferred Shares of every otherseries with respect to accumulated dividends and return of capital.  The Preferred Shares are entitled to apreference over the Common Shares and over any other shares of Penn West rankingjunior to the Preferred Shares with respect to the payment of dividends and thedistribution of assets in the event of the liquidation, dissolution orwinding-up of Penn West, whether voluntary or involuntary, or any otherdistribution of the assets of Penn West among its shareholders for the purpose of winding-up its affairs.  As at the date hereof, no Preferred Sharesare issued and outstanding.

**Borrowing**

We borrow fundsfrom time to time to finance the purchase of properties, for capital expendituresor for other financial obligations or expenditures in respect of propertiesheld by us or for working capital purposes.

Certain debtservice 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 Penn West Petroleum Ltd.

The creditfacilities contain provisions which restrict the ability of Penn West PetroleumLtd. to pay the Trust under the NPIs and interest under the Notes and therebymay restrict distributions to Unitholders in the event of the occurrence ofcertain events of default.  For moreinformation, reference is made to note 6 of our consolidated financialstatements for the year ended December 31, 2006, which are incorporated byreference in this Annual Information Form and which are filed on SEDAR atwww.sedar.com.  For more information, see“Risk Factors — Debt Service”.

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**INFORMATION RELATING TO THE TRUST**

**Trust Units**

An unlimitednumber of Trust Units may be issued pursuant to the Trust Indenture.  The Trust Units represent equal undividedbeneficial interests in the Trust. All Trust Units share equally in alldistributions made by us and all Trust Units carry equal voting rights atmeetings of Unitholders. No Unitholder will be liable to pay any further callsor assessments in respect of the Trust Units. No conversion, retraction orpre-emptive rights attach to the Trust Units.

**Special Voting Units**

The TrustIndenture also provides for the issuance of special voting units and which areentitled 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 for distributionto our Unitholders.  The holders ofspecial voting units will not be entitled to receive dividends or otherdistributions from us.

**Trust Indenture**

The TrustIndenture, 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.

The following is asummary 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 TrustCompany was appointed our trustee on May 27, 2005, and also acts as thetransfer agent for the Trust Units.  TheTrustee is responsible for, among other things, accepting subscriptions forTrust Units and issuing Trust Units pursuant thereto and maintaining our booksand records and providing timely reports to holders of Trust Units.  The Trust Indenture provides that the Trusteeshall exercise its powers and carry out its functions thereunder as Trusteehonestly, in good faith and in our best interests and in the best interest ofthe Unitholders and, in connection therewith, shall exercise that degree ofcare, diligence and skill that a reasonably prudent trustee would exercise incomparable circumstances.

The initial termof the Trustee’s appointment is until the third annual meeting ofUnitholders.  The Unitholders shall, atthe third annual meeting of the Unitholders, re-appoint, or appoint a successorto 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-appointmentor appointment 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.

Penn WestPetroleum Ltd. presently administers us on behalf of the Trustee.  Penn West Petroleum Ltd., on behalf of theTrustee, keeps such books and records as are necessary for the proper recordingof our business transactions.

The TrustIndenture provides that the Trustee shall be under no liability for any actionor 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.

The TrustIndenture also provides that the Trustee may without Unitholder approval amendthe articles of Penn West Petroleum Ltd. to issue shares of Penn West PetroleumLtd. which are exchangeable for Trust Units. There are no exchangeable shares issued or outstanding.

 

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***Future Offerings***

The Trust Indentureprovides that Trust Units, including rights, warrants and other securities topurchase, to convert into or to exchange into Trust Units, may be created,issued, sold and delivered on such terms and conditions and at such times asthe Trustee, upon the recommendation of the Board of Directors maydetermine.  The Trust Indenture alsoprovides that Penn West Petroleum Ltd. 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 andVoting***

Meetings of the Unitholderswill be held annually.  Special meetingsof Unitholders may be called at any time by the Trustee and shall be called bythe Trustee upon the written request of Unitholders holding in aggregate notless than 20 percent of the Trust Units. Notice of all meetings of Unitholders shall be given to Unitholders atleast 21 days prior to the meeting.

Unitholders will beentitled at each annual meeting to appoint our auditors and to elect all themembers of the Board of Directors.

***Our Management***

The Board of Directorshas generally been delegated all of our significant management decisionspursuant to the Trust Indenture and the Administration Agreement.  For more information, see “CorporateGovernance”.

Penn West Petroleum Ltd.has 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 onNon-Resident Ownership***

In order that we maintainour status as a “mutual fund trust” under the *IncomeTax Act* (Canada), certain provisions of the *Income Tax Act* (Canada) require that wenot be established nor maintained primarily for the benefit of non-residents ofCanada (“non-residents”).  The TrustIndenture provides that the Trust will use its best commercial efforts tomaintain its status as a mutual fund trust under the *Income Tax Act* (Canada). See “Risk Factors — Non-Resident Ownership of Trust Units”.

***Right ofRedemption***

Trust Units areredeemable at any time on demand by the holders thereof upon delivery to theTrust 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 “Market Redemption Price”) equal to theleast of: (i) 95 percent of the “market price” of the Trust Units on theprincipal market on which the Trust Units are quoted for trading during the 10trading day period commencing immediately after the date on which the TrustUnits are tendered to the Trust for redemption; (ii) 95 percent of theclosing market price on the principal market on which the Trust Units arequoted for trading on the date that the Trust Units are so tendered forredemption, and (iii) 95 percent of the closing market price of theTrust Units on the date of redemption.

For the purposes of thiscalculation, “market price” will be an amount equal to the simple average ofthe closing price of the Trust Units for each of the trading days on which therewas a closing price; provided that, if the applicable exchange or market doesnot provide a closing price but only provides the highest and lowest prices ofthe Trust Units traded on a particular day, the market price shall be an amountequal to the simple average of the average of the highest and lowest prices foreach of the trading days on which there was a trade; and provided further thatif there was trading on the applicable exchange or market for fewer than fiveof the 10 trading days, the market price shall be the simple average of thefollowing prices established for each of the 10 trading days: the average ofthe last bid and last ask prices for each day on which there was no trading;the closing price of the Trust Units for each day that there was trading if theexchange or market provides a closing price; and the average of the highest andlowest prices of the Trust Units for each day that there was trading, if themarket provides only the highest and lowest prices of Trust Units traded on a particularday.  The closing market price shall be:an amount equal to the closing price of the Trust Units if there was a trade onthe date; an amount equal to the average of the highest and lowest prices ofthe Trust Units if there was trading and the exchange or other market providesonly the 

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highest and lowest pricesof Trust Units traded on a particular day; and the average of the last bid andlast ask prices if there was no trading on the date.

The Market RedemptionPrice payable by the Trust in respect of any Trust Units tendered forredemption during any calendar month shall be satisfied by way of chequepayable on the last day of the calendar month following the month in which theTrust Units were tendered for redemption. The entitlement of Unitholders to receive a cheque upon the redemptionof their Trust Units is subject to the limitation that the total amount payableby the Trust in respect of such Trust Units and all other Trust Units tenderedfor redemption in the same calendar month shall not exceed $250,000 providedthat, Penn West may, in its sole discretion, waive such limitation in respectof any calendar month. If this limitation is not so waived, the MarketRedemption Price payable by the Trust in respect of Trust Units tendered for redemptionin such calendar month shall be paid on the last day of the calendar monthfollowing such month by the Trust distributing redemption notes of Penn WestPetroleum Ltd. to the Unitholders who exercised the right of redemption.

The redemption notes willbe due on the third anniversary of the date of issuance and will bear interestat a rate per annum to be set by the directors of Penn West Petroleum Ltd. inthe 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 Notes.

It is anticipated thatthis redemption right will not be the primary mechanism for holders of TrustUnits to dispose of their Trust Units. Redemption notes which may be distributed in specie to Unitholders inconnection with a redemption will not be listed on any stock exchange and nomarket is expected to develop in such redemption notes.  Redemption notes may not be qualifiedinvestments for trusts governed by registered retirement savings plans,registered retirement income funds, deferred profit sharing plans and registerededucation savings plans.

***Termination of theTrust***

The Unitholders may voteto terminate the Trust at any meeting of the Unitholders, subject to thefollowing: (a) a vote may only be held if requested in writing by theholders of not less than 20 percent of the Trust Units; (b) a quorum of 50percent of the issued and outstanding Trust Units is present in person or byproxy; and (c) the termination must be approved by special resolution ofthe Unitholders.

Unless the Trust isearlier terminated or extended by vote of the Unitholders, the Trustee shallcommence to wind-up the affairs of the Trust on December 31, 2099.  In the event that the Trust is wound-up, theTrustee will liquidate all our assets, pay, retire, discharge or make provisionfor some or all of our obligations and then distribute the remaining proceedsof sale to Unitholders.

***Reporting toUnitholders***

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

Unitholders are entitledto inspect, during normal business hours, at the offices of the Trustee, and,upon payment of reasonable reproduction costs, to receive photocopies of theTrust Indenture and a listing of the registered holders of Trust Units.

**CORPORATE GOVERNANCE**

**General**

In general, Penn WestPetroleum Ltd. has been delegated responsibility for substantially all of themanagement decisions of the Trust. The Unitholders are entitled to elect all ofthe Board of Directors pursuant to the terms of the Trust Indenture.

**Trust Indenture**

Pursuant to the TrustIndenture, Unitholders are entitled to direct the manner in which we will voteour common shares in Penn West Petroleum Ltd. at all meetings in respect ofmatters relating to the election of the directors of Penn West Petroleum Ltd.,approving its financial statements and appointing auditors of Penn West

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Petroleum Ltd. who shallbe the same as our auditors.  Prior to usvoting our common shares in Penn West Petroleum Ltd., in respect of suchmatters, each Unitholder is entitled to vote in respect of the matter on thebasis of one vote per Trust Unit held, and we are required to vote our commonshares in Penn West Petroleum Ltd. in accordance with the result of the vote ofUnitholders.

**Decision Making**

The Board of Directorshas a mandate to supervise the management of our business and affairs, PennWest Petroleum Ltd. and our other direct or indirect subsidiaries andpartnerships and to act with a view to our best interest.  The Board of Directors’ mandateincludes:  (i) any offering ofsecurities; (ii) ensuring compliance with all applicable laws, including inrelation to an offering of securities; (iii) all matters relating to thecontent of any documents relating to an offering of securities, the accuracy ofthe disclosure contained therein, and the certification thereof; (iv) allmatters concerning the terms of, and amendment from time to time of, materialcontracts; (v) all matters concerning any subscription agreement orunderwriting or agency agreement providing for the sale or issue of Trust Unitsor securities convertible for or exchangeable into Trust Units or rights to acquireTrust Units; (vi) all matters relating to the redemption of Trust Units; (vii)all matters relating to the voting rights on any investments; (viii) allmatters relating to the specific powers and authorities as set forth in theTrust Indenture (ix) the adoption of a Unitholder rights plan and othermiscellaneous matters relating to the maximization of Unitholder value; and (x)all matters relating to amending Penn West Petroleum Ltd.’s articles to createexchangeable shares.  The Board ofDirectors holds regularly scheduled meetings at least quarterly to review thebusiness and affairs of our subsidiaries, partnerships and trusts and make anynecessary decisions relating thereto.

The Trust Indenture givesto the Board of Directors the authority to exercise the rights, powers andprivileges for all matters relating to the maximization of Unitholder value inthe context of a take-over bid (an “Offer”) including any Unitholder rightsprotection plan, any defensive action to an Offer, any directors circular inresponse to an Offer, any regulatory or court proceeding relating to an Offerand any related or ancillary matter.

**Distributions and Distribution Policy**

Cash distributions aremade on the 15th day(or if such date is not a business day, on the preceding business day)following the end of each calendar month to Unitholders of record on the lastbusiness day of each such calendar month or such other date as determined fromtime to time by the Trustee.

The Board of Directors onour behalf reviews the distribution policy from time to time.  The actual amount distributed will bedependent on various factors including the commodity price environment and isat the discretion of the Board of Directors of Penn West.  The current distribution policy targets the useof approximately 60 percent to 70 percent of cash flow fordistribution to Unitholders.  Dependingupon various factors including commodity prices and the size of Penn West’scapital budget, it is expected that approximately 30 percent to40 percent of cash flow will fund all or a portion of the Trust’s annualcapital expenditure program, including exploration, exploitation expendituresand minor property acquisitions, but excluding major acquisitions.

Distributions arenormally announced on a monthly basis in the context of prevailing andanticipated commodity prices.  Duringperiods of volatile commodity prices, we may vary the distribution ratemonthly.

Pursuant to theprovisions of the Trust Indenture all taxable income earned by the Trust in afiscal year, not previously distributed in that fiscal year, must bedistributed to Unitholders of record on December 31.  This excess income, if any, will be allocatedto Unitholders of record at December 31 but the right to receive this income,if the amount is not determined and declared payable at December 31, will tradewith the Trust Units until determined and declared payable in accordance withthe rules of the Toronto Stock Exchange. To the extent that a Unitholder trades Trust Units in this period theywill be allocated such income but will dispose of their right to receive thecash or Trust Units comprising such a distribution.

**Directors and Officers**

The name, municipality ofresidence, principal occupation for the prior five years and position, of eachof the directors and officers of Penn West Petroleum Ltd. are as follows:

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***Directors***
| **Name and  Municipality**

**of Residence**                            | ** ** | **Director Since** | ** ** | **Principal Occupation**                                                            |
|-------------------------------------------------------------------------|------------|--------------------|------------|-------------------------------------------------------------------------------------|
| ** **                                                              | ** ** | ** **         | ** ** | ** **                                                                          |
| **James E. Allard(1)**

Calgary, Alberta, Canada                        |       | 2006               |       | Independent director and business advisor                                           |
| ** **                                                              |       |               |       |                                                                                |
| **William E. Andrew**

Calgary, Alberta, Canada                         |       | 1994               |       | President and Chief Executive Officer 

Penn West Petroleum Ltd.                    |
| ** **                                                              |       |               |       |                                                                                |
| **George H. Brookman****(1)(4)(5)**

Calgary, Alberta, Canada           |       | 2005               |       | President and Chief Executive Officer of West  Canadian Industries Group Inc.       |
| ** **                                                              |       |               |       |                                                                                |
| **John A. Brussa**

Calgary, Alberta, Canada                            |       | 1995               |       | Partner, Burnet, Duckworth & Palmer LLP  (barristers and solicitors).           |
| ** **                                                              |       |               |       |                                                                                |
| **Jeffery E. Errico(3)(5)**

Calgary, Alberta, Canada                   |       | 2006               |       | Executive Chairman of Insignia Energy Inc., a  private oil and natural gas company. |
| ** **                                                              |       |               |       |                                                                                |
| **Murray R. Nunns(1)(2)(3)(5)**

Calgary, Alberta, Canada               |       | 2005               |       | Executive Chairman of Monterey Exploration Ltd.                                     |
| ** **                                                              |       |               |       |                                                                                |
| **Thomas E. Phillip****s****(1)(2)(3)(4)(5)**

Calgary, Alberta, Canada |       | 1995               |       | President, Newhaven Investments Inc. (oil and gas  company).                        |
| ** **                                                              |       |               |       |                                                                                |
| **Frank Potter****(2)(4)**

Toronto, Ontario, Canada                    |       | 2006               |       | Chairman of Emerging Markets Advisors, Inc.  (investment consulting firm)           |
| ** **                                                              |       |               |       |                                                                                |
| **James C. Smith****(1)(3)(4)(5)**

Calgary, Alberta, Canada            |       | 2005               |       | Independent director.                                                               |

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Notes:

(1)          Member of audit committee.

(2)          Member of human resources and compensation committee.

(3)          Member of reserves committee.

(4)          Member of the governance committee.

(5)          Member of the health, safety and environmentcommittee.

All of the directors haveheld the principal occupation set forth beside their name for the last fiveyears except for the following: Murray R. Nunns, from 2002 to 2005, wasPresident, Chief Executive Officer and Director of Crispin Energy Inc. andprior thereto held various management positions at Rio Alto Exploration Ltd.including Chief Operating Officer. Jeffery E. Errico was President and CEO of Petrofund Energy Trust since2003 and President of Petrofund Energy Trust prior thereto, and James C. Smithwho was also Chief Financial Officer of Mercury Energy Corporation, a privateoil and natural gas company, from 2002 to 2006.

Each of the directorswill hold office until the next annual meeting of Unitholders of the Trust oruntil their successors are elected or appointed.

***Executive Officers***

| Name and Municipality of  Residence                | ** ** | **Office and  Principal Occupation**                 |
|----------------------------------------------------|------------|------------------------------------------------------|
| ** **                                         | ** ** | ** **                                           |
| **William  Andrew******

Calgary,  Alberta, Canada |       | President and Chief Executive Officer                |
| ** **                                         |       |                                                 |
| **David  Middleton**

Calgary,  Alberta, Canada    |       | Executive Vice President and Chief Operating Officer |
| ** **                                         |       |                                                 |
| **Thane  Jensen**

Calgary,  Alberta, Canada       |       | Senior Vice President, Exploration and Development   |
| ** **                                         |       |                                                 |
| **Todd  Takeyasu**

Calgary,  Alberta, Canada      |       | Senior Vice President and Chief Financial Officer    |

 

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| **William Tang Kong**

Calgary,  Alberta, Canada |   | Senior Vice President, Corporate Development |
|--------------------------------------------------|--------|----------------------------------------------|
| ** **                                       |   |                                         |
| **Anne  Thomson**

Calgary,  Alberta, Canada     |   | Vice President, Exploration                  |
| ** **                                       |   |                                         |
| **Eric  Obreiter**

Calgary,  Alberta, Canada    |   | Vice President, Production                   |
| ** **                                       |   |                                         |
| **Gregg  Gegunde**

Calgary,  Alberta, Canada    |   | Vice President, Development                  |
| ** **                                       |   |                                         |
| **Kristian  Tange**

Calgary,  Alberta, Canada   |   | Vice President, Business Development         |
| ** **                                       |   |                                         |
| **Lucas  Law**

Calgary,  Alberta, Canada        |   | Vice-President, Asset Management             |
| ** **                                       |   |                                         |
| **Keith  Luft**

Calgary,  Alberta, Canada       |   | Vice-President, Land and Legal               |

The above appointments as officers were effective June2005 except for William Tang Kong, Todd Takeyasu, Lucas Law and KeithLuft.  In the preceding 5 years, theabove officers held the principal occupations set forth except:  David Middleton was Senior Vice President,Production since 2003 and prior thereto Vice President, Production since 2001;Thane Jensen was Vice President, Engineering since 2004 and prior theretoManager, Exploitation since 2001; Todd Takeyasu was Vice President, Financesince 2005 and prior thereto Treasurer since 2001; William Tang Kong was VicePresident, Corporate Development since 2005 and prior thereto Manager,Corporate Development since 2001; Anne Thomson was Manager, Exploration since2003 and prior thereto District Geologist since 2001; Eric Obreiter wasManager, Production Central since 2001; Gregg Gegunde was Manager, ProductionPlains since 2003 and prior thereto Senior Engineer since 2001; Kristian Tangewas Manager, Marketing since 2003 and prior thereto Manager, Natural GasMarketing since 2001.  Lucas Law wasManager, Corporate Development since 2005, Supervisor, Exploitation since 2004and prior thereto Team Leader, Petrovera Resources since 2001.  Keith Luft was Senior Solicitor, ConocoPhillips Canada Ltd./Burlington Resources Canada Ltd. since May 2004 and priorthereto a partner in a Calgary based law firm since 2001.

As at March 22,2007, the directors and officers of Penn West Petroleum Ltd., as a group,beneficially owned, directly or indirectly, or exercised control or directionover, 819,635 Trust Units or approximately 0.34 percent of the issued andoutstanding Trust Units.

**Corporate Cease Trade Orders or Bankruptcies**

Except as otherwisedisclosed herein, in the ten years preceding the date of this AnnualInformation Form, none of the proposed directors, officers or insiders of PennWest Petroleum Ltd. are or have been a director, officer or promoter of anyother issuer that, while acting in such capacity:

(a)                                  wasthe subject of a cease trade or similar order or an order that denied theissuer access to any statutory exemptions for a period of more than 30consecutive days; or

(b)                                 wasdeclared bankrupt or made a voluntary assignment in bankruptcy, made a proposalunder any legislation relating to bankruptcy and insolvency or been subject toor instituted any proceedings, arrangement, or compromise with creditors or hada receiver, receiver manager or trustee appointed to hold the assets of thatperson’s stock.

John A. Brussa was adirector of Imperial Metals Limited, a corporation engaged in both oil and gasand mining operations, in the year prior to that corporation implementing aplan of arrangement under the *Company Act*(British Columbia) and under the *Companies’Creditors Arrangement Act* (Canada) which resulted in the separationof its two businesses.  Thereorganization resulted in the creation of two public corporations, ImperialMetals Corporation and IEI Energy Inc. (now Rider Resources Ltd.), both ofwhich trade on the Toronto Stock Exchange.

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James C. Smith was, fromMay 1999 to March 2000, Vice President and Chief Financial Officer of ProbeExploration Inc., an oil and gas company listed on the Toronto StockExchange.  Mr. Smith joined ProbeExploration Inc. in order to assist management and the Board of Directors ofthe company in their efforts to restructure the company’s finances or sellassets to improve its financial situation. Such efforts did not succeed and the company’s lender appointed areceiver in March 2000.

**Penalties or Sanctions**

None of the proposeddirectors, officers or insiders of Penn West Petroleum Ltd. have been subjectto any penalties or sanctions under securities legislations except as disclosedherein.

**Personal Bankruptcies**

None of the directors,officers or insiders of Penn West Petroleum Ltd. have in the ten yearspreceding the date of this Annual Information Form become bankrupt, made aproposal under any legislation relating to bankruptcy or insolvency, or beensubject to or instituted any proceedings, arrangement or compromise withcreditors or had a receiver, receiver manager or trustee appointed to holdtheir assets except as disclosed herein.

**Conflicts of Interest**

The Board of Directorshas adopted 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, directorsand officers 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 President and Chief Executive Officer or the Board ofDirectors.  Any other activities posing apotential conflict of interest are also required by the Codes to be disclosedto the President and Chief Executive Officer or the Board of Directors.  Any such potential conflicts of interestswill be dealt with openly with full disclosure of the nature and extent of thepotential conflicts of interests with the Trust.

It is acknowledged in theCodes that the directors may be directors or officers of other entities engagedin the oil and gas business, and that such entities may compete directly orindirectly with the Trust.  Passiveinvestments in public or private entities of less than one per cent of theoutstanding shares will not be viewed as “competing” with the Trust.  No executive officer or employee of Penn Westshould be a director or officer of any entity engaged in the oil and gasbusiness unless expressly authorized by the Board of Directors.  Any director of Penn West 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.  Inthe event that any circumstance should arise as a result of such positions orinvestments being held or otherwise which in the opinion of the Board ofDirectors constitutes a conflict of interest which reasonably affects suchperson’s ability to act with a view to the best interests of the Trust, theBoard of Directors will take such actions as are reasonably required to resolvesuch matters with a view to the best interests of the Trust.  Such actions, without limitation, may includeexcluding such directors, officers or employees from certain information oractivities of the Trust.

The *Business Corporations Act* (Alberta)provides that in the event that an officer or director is a party to, or is adirector or an officer of or has a material interest in any person who is aparty to, a material contract or material transaction or proposed materialcontract or proposed material transaction, such officer or director shalldisclose the nature and extent of his or her interest and shall refrain fromvoting to approve such contract or transaction.

**AUDITCOMMITTEE DISCLOSURES**

Multilateral Instrument52-110 (“MI 52-110”) relating to audit committees has mandated certaindisclosures for inclusion in this Annual Information Form.  The text of the Audit Committee’s mandate isattached as Appendix C to this Annual Information Form.

The members of the AuditCommittee are James C. Smith, chairman, and James E. Allard,George H. Brookman, Murray R. Nunns and Thomas E. Phillips, each ofwhom is independent and financially literate within the meaning of MI 52-110.  The following comprises a brief summary ofeach member’s education and experience:

***James C. Smith(Chairman)***

Mr. Smith is a CharteredAccountant with over 30 years of experience in public accounting andindustry.  Since 1998, he has been abusiness consultant to a number of public and private companies operating inthe oil and gas industry.  From 2002until its sale in 2006, he was also the Chief Financial Officer of MercuryEnergy Corporation, a private oil and natural gas

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company and from 2001until the sale of the company in 2003, was the Chief Financial Officer of SegueEnergy Corporation, a private oil and natural gas company. From 1999 to 2000,Mr. Smith was the Vice President and Chief Financial Officer of ProbeExploration Inc., a publicly traded oil and natural gas company. While Mr.Smith was the Vice President and Chief Financial Officer of Crestar Energy Inc.from its inception in 1992 until 1998, the company completed an initial publicoffering, was listed on the Toronto Stock Exchange and completed several majordebt and equity financing transactions. Mr. Smith is currently a director ofGrand Petroleum Inc., TAG Oil Ltd., Pure Energy Services Inc., and Grey WolfExploration Inc.

***James E. Allard***

Mr. Allard received hisBachelor of Science degree in Business Administration from the University ofConnecticut and completed the Advanced Management Program at HarvardUniversity.  Mr. Allard has focused hiscareer on international finance in the petroleum industry for the past 40 yearsserving as CEO, CFO and a director of a number of publicly traded and privatecompanies.  During the past seven yearshe served on the board of the Alberta Securities Commission, acting as the soleexternal trustee and advisor to a mid-sized pension plan and serves as adirector and advisor to several companies. From 1981 to 1995, he served as a senior executive officer of AmocoCorporation as well as a director of Amoco Canada, then Canada’s largestnatural gas producer.

***George H. Brookman***

Mr. Brookman acquiredWest Canadian Industries Group in 1984 and under his leadership it has becomeone of Canada’s largest privately held digital printing and imaging servicecompanies.

He is also a partner inVistek, a major retail camera operation with stores in Toronto, Calgary and oneunder construction in Edmonton and was the founder of Commonwealth Legal Inc.,Canada’s only national litigation support services operating in six Canadiancities.  Prior to acquiring West CanadianIndustries Group, Mr. Brookman was involved for many years in the commercialdevelopment industry in the Real Estate Group of Manulife and later as the VicePresident of ATCO Development Ltd.

In addition to histhirty-five years of business experience, Mr. Brookman has been active in thecommunity and is currently the Chairman elect of the Calgary Exhibition andStampede.  He is also on the advisoryBoard of the Department of Communications and Culture of the University ofCalgary, a Director of KSPS Television in Spokane, Washington and Past Presidentof the Rotary Club of Calgary.

***Murray R. Nunns***

Mr. Nunns is currentlythe Executive Chairman of Monterey Exploration Ltd. and is also a director ofseveral other oil and gas companies in Western Canada including Capital EnergyLtd. and three additional private junior oil and natural gas companies.  Mr. Nunns has over 25 years of experiencewith domestic and international oil and natural gas exploration and productionactivities.  From 2003 to 2005, Mr. Nunnsserved as President, CEO and Director of Crispin Energy Inc. and from 1993 to2002, held a variety of management positions at Rio Alto Exploration Ltd.including Executive Vice President of Exploration and Development and ChiefOperating Officer.  From 1986 to 1993,Mr. Nunns worked in several capacities with Unocal Exploration Ltd. includingChief Geologist for Unocal Canada and in portfolio management of itsinternational exploration program.  Mr.Nunns is a graduate of the University of Toronto and holds a Bachelor ofScience (Honours) in Geology.

***Thomas E. Phillips***

Mr. Phillips is thePresident of Newhaven Investments Inc., a private company engaged in theacquisition, drilling and production of oil and natural gas in Alberta, andland development on the Sunshine Coast of British Columbia.  He studied mathematics at the University ofBritish Columbia and in 1976 received his Bachelor of Science degree from theUniversity of Calgary with a major in geology and minor in computerscience.  He has worked at severalcompanies including Home Oil, Placid Oil, and Placer CEGO and served asPresident of Albany Oil & Gas and Northern Reef Exploration Ltd.  Mr. Phillips has been a Director of Penn Westsince 1995.

The terms of theengagement of Penn West’s external auditors to provide audit services,including the budgeted fees for such audit services and the representations anddisclaimer relating thereto, must be pre-approved by the entire AuditCommittee.

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With respect to anyengagements of Penn West’s external auditors for non-audit services, Penn Westmust obtain the approval of the Audit Committee or the Chairman of the AuditCommittee prior to retaining the external auditors to complete suchengagement.  If such pre-approval isprovided by the Chairman of the Audit Committee, the Chairman shall report to theAudit Committee on any non-audit service engagement pre-approved by him at theAudit Committee’s first scheduled meeting following such pre-approval.

If, after using itsreasonable best efforts, Penn West is unable to contact the Chairman of theAudit Committee on a timely basis to obtain the pre-approval contemplated bythe preceding paragraph, Penn West may obtain the required pre-approval fromany other 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.

The following is asummary of the fees paid to KPMG LLP for external audit and other services.

***Audit Fees***

The aggregate fees billedby our external auditor for audit services were:

| 2006   | — | $485,000 |
|--------|--------|----------|
|   |   |     |
| 2005   | — | $215,000 |

 

***Audit Related Fees***

The aggregate fees billedby our external auditor for assurance and related services that are reasonablyrelated to the performance of the audit or review of the financial statements(not included in audit services fees) were:

| 2006   | — | $230,000 |
|--------|--------|----------|
|   |   |     |
| 2005   | — | $187,500 |

 

***Tax Fees***

The aggregate fees billedby our external auditor for professional services for tax compliance, taxadvice and tax planning were:

| 2006   | — | $18,341 |
|--------|--------|---------|
|   |   |    |
| 2005   | — | $42,738 |

 

***All Other Fees***

The aggregate fees billedby our external auditor for products and services not included under theheadings Audit Fees, Audit Related Fees and Tax Fees were:

| 2006   | — | $NIL   |
|--------|--------|--------|
|   |   |   |
| 2005   | — | $NIL   |

 

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**DISTRIBUTIONSTO UNITHOLDERS**

Since our formation as atrust, monthly cash distributions were declared in 2005 and 2006 in thefollowing amounts, each amount being paid in the following month:

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

 

For Canadian income tax purposes, cash distributionspaid to Unitholders in 2006 and 2005 were 100 percent taxable as other income.

**MARKETFOR SECURITIES**

The Trust Units arelisted and traded on the Toronto Stock Exchange (“TSX”) under the symbol PWT.UNand on the New York Stock Exchange (“NYSE”) under the symbol PWE.  The following tables set forth tradinginformation for our Trust Units in 2006.

|            | ** ** | **TSX**                      | ** ** |
|------------|------------|------------------------------|------------|
| ** ** | ** ** | **Unit price ($)** | ** ** | **Unit price ($)** | ** ** | ** ** | ** ** |
| **Period** | ** ** | **High**                     | ** ** | **Low** | ** ** | **Volume** | ** ** |
|       |       |                         |       |   |   |   |   |
| January    |       | 43.37                        |       | 38.06 |   | 23,178,660 |   |
| February   |       | 44.69                        |       | 37.86 |   | 22,155,294 |   |
| March      |       | 44.06                        |       | 39.10 |   | 16,116,224 |   |
| April      |       | 45.24                        |       | 41.37 |   | 17,311,732 |   |
| May        |       | 47.50                        |       | 38.90 |   | 19,502,095 |   |
| June       |       | 45.30                        |       | 38.85 |   | 22,996,544 |   |
| July       |       | 45.48                        |       | 42.00 |   | 18,177,470 |   |
| August     |       | 47.77                        |       | 45.10 |   | 18,380,207 |   |
| September  |       | 46.08                        |       | 38.68 |   | 23,573,983 |   |
| October    |       | 44.40                        |       | 35.60 |   | 38,956,721 |   |
| November   |       | 38.49                        |       | 31.60 |   | 53,881,368 |   |
| December   |       | 37.56                        |       | 35.30 |   | 14,828,854 |   |

 

|            | ** ** | **NYSE**                       | ** ** |
|------------|------------|--------------------------------|------------|
| ** ** | ** ** | **Unit price ($US)** | ** ** | **Unit price ($US)** | ** ** | ** ** | ** ** |
| **Period** | ** ** | **High**                       | ** ** | **Low** | ** ** | **Volume** | ** ** |
|       |       |                           |       |   |   |   |   |
| June(1)    |       | 40.20                          |       | 37.20 |   | 1,907,200 |   |
| July       |       | 41.09                          |       | 37.40 |   | 7,733,100 |   |
| August     |       | 42.98                          |       | 40.02 |   | 10,105,100 |   |
| September  |       | 41.46                          |       | 35.39 |   | 14,942,300 |   |
| October    |       | 39.38                          |       | 31.50 |   | 13,124,000 |   |
| November   |       | 34.00                          |       | 27.74 |   | 39,446,400 |   |
| December   |       | 32.72                          |       | 30.35 |   | 15,114,700 |   |

----

Note:

(1)                                  Trading on NYSE began on June 22,2006.

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**INDUSTRYCONDITIONS**

The oil and natural gasindustry is subject to extensive controls and regulations governing itsoperations (including land tenure, exploration, development, production,refining, transportation, and marketing) imposed by legislation enacted byvarious levels of government and with respect to pricing and taxation of oiland natural gas by agreements among the governments of Canada, Alberta, BritishColumbia and Saskatchewan, all of which should be carefully considered byinvestors in the oil and gas industry. It is not expected that any of thesecontrols or regulations will affect our operations in a manner materiallydifferent than they would affect other oil and gas companies of similar size.All current legislation is a matter of public record and we are unable topredict what additional legislation or amendments may be enacted. Outlinedbelow are some of the principal aspects of legislation, regulations and agreementsgoverning the oil 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, and other contractual terms. Oil exportersare also entitled to enter into export contracts with terms not exceeding oneyear in the case of light crude oil and two years in the case of heavy crudeoil, provided that an order approving such export has been obtained from theNational 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 gasis determined by negotiation between buyers and sellers. Natural gas exportedfrom Canada is subject to regulation by the NEB and the Government of Canada.Exporters are free to negotiate prices and other terms with purchasers, providedthat the export contracts must continue to meet certain other criteriaprescribed by the NEB and the Government of Canada. Natural gas exports for aterm of less than two years or for a term of two years to 20 years (inquantities of not more than 30,000 m3/day), must be made pursuant to an NEBorder. Any natural gas export to be made pursuant to a contract of longerduration (to a maximum of 25 years) or a larger quantity requires an exporterto obtain an export licence from the NEB and the issuance of such licencerequires the approval of the Governor in Council.

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

**Pipeline Capacity**

Although pipelineexpansions are ongoing, the lack of firm pipeline capacity continues to affectthe oil and natural gas industry and limit the ability to produce and to marketnatural gas production. In addition, the pro-rationing of capacity on theinter-provincial pipeline systems also continues to affect the ability toexport oil and natural gas.

**The North American Free Trade Agreement**

The North American FreeTrade Agreement (“NAFTA”) among the governments of Canada, United States ofAmerica, and Mexico became effective on January 1, 1994. NAFTA carriesforward most of the material energy terms that are contained in the CanadaUnited States Free Trade Agreement. In the context of energy resources, Canadacontinues to remain free to determine whether exports of energy resources tothe United States or Mexico will be allowed, provided that any exportrestrictions do not: (i) reduce the proportion of energy resources exportedrelative to domestic use (based upon the proportion prevailing in the mostrecent 36 month period); (ii) impose an export price higher than the domesticprice subject to an exception with respect to certain voluntary measures whichonly restrict the volume of exports; and (iii) disrupt normal channels ofsupply. All three countries are prohibited from imposing minimum or maximumexport or import price requirements, provided, in the case of export pricerequirements, prohibition in any circumstances in which any other form ofquantitative restriction is prohibited, and in the case of import-pricerequirements, such requirements do not apply with respect to enforcement ofcountervailing and anti-dumping orders and undertakings.

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NAFTA contemplatesthe reduction of Mexican restrictive trade practices in the energy sector by2010 and prohibits discriminatory border restrictions and export taxes. NAFTAalso contemplates clearer disciplines on regulators to ensure fairimplementation of any regulatory changes and to minimize disruption ofcontractual arrangements and avoid undue interference with pricing, marketingand distribution arrangements, which is important for Canadian natural gasexports.

**Provincial Royalties and Incentives**

***General***

In addition tofederal regulation, each province has legislation and regulations which governland tenure, royalties, production rates, environmental protection, and othermatters. The royalty regime is a significant factor in the profitability of crudeoil, 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 also 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 thegovernments of the western Canadian provinces create incentive programs forexploration and development. Such programs often provide for royalty ratereductions, royalty holidays, and tax credits, and are generally introducedwhen commodity prices are low. The programs are designed to encourageexploration and development activity by improving earnings and cash flow withinthe industry. Royalty holidays and reductions would reduce the amount of Crownroyalties paid by oil and gas producers to the provincial governments and wouldincrease the net income and funds from operations of such producers. However,the trend in recent years has been for provincial governments to eliminate,amend or allow such incentive programs to expire without renewal, andconsequently few such incentive programs are currently operative.

The Canadianfederal corporate income tax rate levied on taxable income is 22.1 percenteffective January 1, 2007 for active business income including resourceincome.  With the elimination of thecorporate surtax effective January 1, 2008 and other rate reductionsintroduced in the 2006 Federal Budget, the federal corporate income taxrate will decrease to 19 percent in three steps: 20.5 percent onJanuary 1, 2008; 20 percent on January 1, 2009 and 19 percent onJanuary 1, 2010.

***Alberta***

In Alberta, companiesare granted 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 in “new oil” and “old oil” depending on when the oil pools werediscovered. If discovered prior to March 31, 1974 is considered “old oil”,if discovered after March 31, 1974 and before September 1, 1992, isconsidered “new oil”. The Alberta government introduced in 1992 a Third TierRoyalty with a base rate of 10 percent and a rate cap of 25 percentfor oil pools discovered after September 1, 1992. The new oil royaltyreserved to the Crown has a base rate of 10 percent and a rate cap of30 percent. The old oil royalty reserved to the Crown has a base rate of10 percent and a rate cap of 35 percent.

The royaltyreserved to the Crown in respect of natural gas production, subject to variousincentives, is between 15 percent and 30 percent, in the case of newnatural gas, and between 15 percent and 35 percent, in the case ofold natural gas, depending upon a prescribed or corporate average referenceprice. Natural gas produced from qualifying intervals in eligible gas wellsspudded or deepened to a depth below 2,500 metres is also subject to a royaltyexemption, the amount of which depends on the depth of the well.

Oil sands projectsare subject to a specific regulation made effective July 1, 1997, andexpiring June 30, 2007, which, among other things, determines the Crown’sshare of crude and processed oil sands products.

Regulations madepursuant to the *Mines and Minerals Act*(Alberta) provided various incentives for exploring and developing oil reservesin Alberta. However, the Alberta Government announced in August of 2006 thatfour royalty programs were to be amended, a new program was to be introducedand the Alberta Royalty Tax Credit Program (“ARTC”) was to be eliminated,effective January 1, 2007. The programs affected by this announcement are:(i) Deep Gas Royalty Holiday; (ii) Low Productivity Well Royalty Reduction;(iii) Reactivated Well Royalty Exemption; and (iv) Horizontal Re-Entry RoyaltyReduction. The program being introduced is the Innovative Energy TechnologiesProgram (the “IETP”) which is intended to 

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promote theproducers’ investment in research, technology and innovation for the purposesof improving environmental performance while creating commercial value. TheIETP provides royalty reductions which are presumed to reduce financial risk.Alberta Energy will be the one to decide which projects qualify and the levelof support that will be provided. The deadline for the IETP’s third round ofapplications is May 31, 2007.

On February 16,2007, the Alberta Government announced that a review of the province’s royaltyand tax regime (including income tax and freehold mineral rights tax)pertaining to oil, gas and oil sands will be conducted by a panel of experts,with the assistance of individual Albertans and key stakeholders. The purposeof this process is to ensure that Albertans are receiving a fair share fromenergy development through royalties, taxes and fees. The issues to be reviewedduring this examination process are: (i) undertaking a comparison of Alberta’sroyalty system to other oil and gas producing jurisdictions, taking intoaccount investment economics and industry returns and risks in Alberta; (ii)whether Alberta’s royalty system is sufficiently sensitive to marketconditions; (iii) whether the current revenue minus cost system for oil sandsroyalties is optimal; (iv) which programs built into the existing royaltysystem should be retained or strengthened, and which should be adapted oreliminated; (v) how the tax treatment of the oil and gas sector compares toother sectors and jurisdictions; (vi) the economic and fiscal impacts of anypossible changes to the royalty and corporate tax structures; and (vii) howexisting resource development should be treated if changes are to be made tothe fiscal regime. The review panel is to produce a final report that will bepresented to the Minister of Finance by August 31, 2007.

***British Columbia***

Producers of oiland natural gas in the Province of British Columbia are required to pay annualrental payments with respect to the Crown leases and royalties and freeholdproduction taxes in respect of oil and gas produced from Crown and freeholdlands. The amount payable as a royalty in respect of oil depends on the type ofoil, the value of the oil, the quantity of oil produced in a month, and thevintage of the oil. Generally, the vintage of oil is based on the determinationof whether the oil is produced from a pool discovered before October 31,1975 (old oil), between October 31, 1975, and June 1, 1998 (new oil), orafter June 1, 1998 (third-tier oil). The royalty rates are calculated in threestages, which take into account the vintage of the oil, if the oil produced hasalready been sold and any royalty exempt value applicable (exempt wells). Oilproduced from newly discovered pools may be exempt from the payment of aroyalty for the first 36 months of production or 11,450 m3 produced, whichever comes first; and theroyalties for third-tier oil are the lowest reflecting the higher costs ofexploration and extraction that the producers would incur. The royalty payableon natural gas is determined by a sliding scale based on a reference price,which is the greater of the price obtained by the producer, and a prescribedminimum price. However, when the reference price is below the select price (aparameter used in the royalty rate formula), the royalty rate is fixed. As anincentive for the production and marketing of natural gas, which may have beenflared, natural gas produced in association with oil has a lower royalty thenthe royalty payable on non-conservation gas.

On May 30, 2003,the Ministry of Energy and Mines for the Province of British Columbia announcedan Oil and Gas Development Strategy for the Heartlands (“Strategy”). TheStrategy is a comprehensive program to address road infrastructure, targetedroyalties and regulatory reduction, and British Columbia service sectoropportunities. In addition, the Strategy will result in economic and employmentopportunities for communities in British Columbia’s heartlands.

Some of thefinancial incentives in the Strategy include:

·                                          Royaltycredits of up to $30 million annually towards the construction, upgrading, andmaintenance of road infrastructure in support of resource exploration anddevelopment. Funding will be contingent upon an equal contribution fromindustry.

·                                          Changesto provincial royalties: new royalty rates for low productivity natural gas toenhance marginally economic resources plays, royalty credits for deep gas explorationto locate new sources of natural gas, and royalty credits for summer drillingto expand the drilling season.

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. Withregards to the oil and gas industry, the objective is to achieve clean energythrough conservation and energy efficient practices, whilst competitiveness isadvocated in order to attract investment for the development of the oil and gassector. Among the changes to be implemented are: (i) a new of Net ProfitRoyalty Program; (ii) the creation of a Petroleum Registry; (iii) theestablishing of an infrastructure royalty program (combining roads andpipelines); (iv) the elimination of routine flaring at producing wells; (v) thecreation of policies and measures for the reduction of emissions; (vi) thedevelopment of unconventional resources such as tight gas and coalbed gas; and(vii) new the Oil and Gas Technology Transfer Incentive Program that encouragesthe 

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research,development and use of innovative technologies to increase recoveries fromexisting reserves and promotes responsible development of new oil and gasreserves.

***Saskatchewan***

In Saskatchewan,the amount payable as a royalty in respect of oil depends on the vintage of theoil, the type of oil, the quantity of oil produced in a month, and the value ofthe oil. For Crown royalty and freehold production tax purposes, crude oil isconsidered “heavy oil”, “southwest designated oil”, or “non-heavy oil otherthan southwest designated oil”. The conventional royalty and production taxclassifications (“fourth-tier oil” introduced October 1, 2002, “third-tieroil”, “new oil”, or “old oil”) of oil production are applicable to each of thethree crude oil types. The Crown royalty and freehold production tax structurefor crude oil is price sensitive and varies between the base royalty rates of5 percent for all “fourth-tier oil” to 20 percent for “old oil”.Marginal royalty rates are 30 percent for all “fourth-tier oil” to45 percent for “old oil”.

The amount payableas a royalty in respect of natural gas is determined by a sliding scale basedon a reference price (which is the greater of the amount obtained by theproducer and a prescribed minimum price), the quantity produced in a givenmonth, the type of natural gas, and the vintage of the natural gas. As anincentive for the production and marketing of natural gas which may have beenflared, the royalty rate on natural gas produced in association with oil isless than on non-associated natural gas. The royalty and production taxclassifications of gas production are “fourth-tier gas” introduced October 1,2002, “third-tier gas”, “new gas”, and “old gas”. The Crown royalty andfreehold production tax for gas is price sensitive and varies between the baseroyalty rate of 5 percent for “fourth-tier gas” and 20 percent for “oldgas”. The marginal royalty rates are between 30 percent for “fourth -tiergas” and 45 percent for “old gas”.

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

·                  Anew Crown royalty and freehold production tax regime applicable to associatednatural gas (gas produced from oil wells) that is gathered for use or sale. Theroyalty/tax will be payable on associated natural gas produced from an oil wellthat exceeds approximately 65 thousand cubic metres in a month.

·                  Amodified system of incentive volumes and maximum royalty/tax rates applicableto the initial production from oil wells and gas wells with a finished drillingdate on or after October 1, 2002, was introduced. The incentive volumes areapplicable to various well types and are subject to a maximum royalty rate of2.5 percent and a freehold production tax rate of zero percent.

·                  Theelimination of the re-entry and short section horizontal oil well royalty/taxcategories. All horizontal oil wells with a finished drilling date on or afterOctober 1, 2002, will receive the “fourth tier” royalty/ tax rates and newincentive volumes.

In 1975, theGovernment of Saskatchewan introduced a Royalty Tax Rebate (“RTR”) as aresponse to the Government of Canada disallowing crown royalties and similartaxes as a deductible business expense for income tax purposes. As of January1, 2007, the remaining balance of any unused RTR will be limited in its carryforward to five years since the Government of Canada had the initiative toreintroduce the full deduction of provincial resource royalties from federaland provincial taxable income.

**Land Tenure**

Crude oil andnatural gas located in the western provinces is owned predominantly by therespective provincial governments. Provincial governments grant rights toexplore for and produce oil and natural gas pursuant to leases, licences, andpermits for varying terms, the minimum of which is two years, and on conditionsset forth in provincial legislation including requirements to perform specificwork or make payments. Oil and natural gas located in such provinces can alsobe privately owned and rights to explore for and produce such oil and naturalgas are granted by lease on such terms and conditions as may be negotiated.

**Environmental Regulation**

The oil andnatural gas industry is currently subject to environmental regulations pursuantto a variety of provincial and federal legislation. Environmental regulationsimpose, among other things, restrictions, liabilities and obligations inconnection with the generation, handling, storage, transportation, treatmentand disposal of hazardous substances and waste and in connection with spills,releases and emissions of various substances to the environment.  Environmental legislation 

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also requires thatwells, facility sites and other properties associated with our operations beoperated, maintained, abandoned and reclaimed to the satisfaction of applicableregulatory authorities.  In addition,certain types of operations, including exploration and development projects andsignificant changes to certain existing projects, may require the submissionand approval of environmental impact assessments or permit applications.  Compliance with such legislation can requiresignificant expenditures and a breach of such requirements may result insuspension or revocation of necessary licenses and authorizations, civilliability for pollution damage and the imposition of material fines andpenalties.

Environmentallegislation in the Province of Alberta has been consolidated into the *Environmental Protection and Enhancement Act*(Alberta) (the “EPEA”), whichcame into force on September 1, 1993, and the *Oil and Gas Conservation 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 enacted regulationspursuant to the EPEA to specifically target sulphur oxide and nitrous oxideemissions from industrial operations including the oil and gas industry.  No additional expenses are foreseen that areassociated with complying with the new regulations.  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, and will betaking such steps as required to ensure compliance with the EPEA and similarlegislation in other jurisdictions in which it operates.  We believe that we will be in materialcompliance with applicable environmental laws and regulations.  We also believe that it is reasonably likelythat the trend towards stricter standards in environmental legislation andregulation will continue.

British Columbia’s*Environmental Assessment Act*became effective June 30, 1995. This legislation rolls the previous processes for the review of majorenergy projects into a single environmental assessment process with publicparticipation in the environmental review process.

In December, 2002,the Government of Canada ratified the Kyoto Protocol that became legallybinding on February 16, 2005.  Thisprotocol calls for Canada to reduce its greenhouse gas emissions to six percentbelow 1990 levels during the period between 2008 and 2012.  The protocol is expected to affect theoperation of all industries in Canada, including the oil and gas industry.  As details of the implementation of thisprotocol have yet to be announced, the effect on our operations cannot bedetermined at this time.

The Government ofCanada has announced its intention to regulate greenhouse gases (“GHG”) andother air pollutants.  The Government iscurrently developing a framework that outlines its clean air and climate changeaction plan, including a target to reduce GHG emissions by 45 percent to 65percent by 2050 and a commitment to regulate industry on an emissions intensitybasis in the short-term.  Currently thereare few technical details regarding the implementation of the Government’s planto regulate industrial GHG emissions, but the Government has made a commitmentto work with industry to develop the specifics.

The AlbertaGovernment has also released draft regulations that will require facilitiesthat emit over 100,000 tonnes of CO2E/yr (total Greenhouse Gases in terms ofCO2 equivalent) to reduce their emissionsintensity (quantity of gases releases per unit of production) by12 percent starting July 1, 2007. Facilities that do not reduce their emissions intensity by this amountwill either be charged $15/tonne for every tonne they are over the12 percent target or they will have to invest in projects outside of theirfacility, but still in Alberta, that reduce or offset emissions on theirbehalf.  Penn West currently does notoperate any facilities that fall under the current regulations but it does havea working interest in some facilities that do. The full impact of this regulation is currently unknown but it is verylikely that these targets will result in increased operating costs forfacilities that are under these regulations. However, Penn West believes that this new regulation will be of overallbenefit to the Trust as it will most likely result in increased interest in CO2 capture and storage technologies andinfrastructure that will increase the speed of development of its CO2 injection plans in Pembina.

As the federal andprovincial programs are under development, Penn West is unable to predict thetotal impact of the potential regulations upon its business. Therefore, it ispossible that we could face increases in operating costs in order to complywith GHG emissions legislation. However, Penn West in cooperation with theCanadian Association of Petroleum Producers will continue to work with theGovernment to develop an approach to deal with climate change issues thatprotects the industry’s competitiveness, limits the cost and administrativeburden of compliance and supports continued investment in the sector.  In the meantime, we will continue its currentactivities to reduce emissions intensity, improve energy efficiency and developCO2 injection and sequestrationinfrastructure.  See “Risk Factors —Environmental” and “Risk Factors — Kyoto Protocol”.

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**RISK FACTORS**

The following is asummary of certain risk factors relating to our business which prospectiveinvestors should carefully consider before deciding whether to purchase TrustUnits.

**Volatility of Oil and Natural Gas Prices**

Our operationalresults and financial condition of our operating entities and therefore theamounts paid to us will be dependent on the prices received for oil and naturalgas production. Oil and natural gas prices have fluctuated widely duringrecent years and are determined by economic, and in the case of oil prices,also political factors.  Supply anddemand factors, including weather and general economic conditions, as well asconditions in other oil and natural gas regions impact prices.  Any movement in oil and natural gas priceswill have an effect on our cash flow from operations, financial condition andtherefore on our financial position and the cash available to be distributed toUnitholders.  We may manage the riskassociated with changes in commodity prices by entering into oil or natural gasprice hedges.  If we hedge our commodityprice exposure, we could forego the benefits we would otherwise experience ifcommodity prices were to increase.  Inaddition, commodity hedging activities could expose us to cash and incomelosses.  To the extent that we engage inrisk management activities related to commodity prices, there are credit risksassociated with counterparties with which we contract.

**Variations in Foreign Exchange Rates and InterestRates**

World oil pricesare quoted in United States dollars and the price received by Canadianproducers is therefore affected by the Canadian/U.S. dollar exchange rate thatmay fluctuate over time.  A materialincrease in the value of the Canadian dollar may negatively impact ouroperating entities production revenues**.**  The 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 thatwe engage in risk management activities related to foreign exchange rates,there is credit risk associated with counterparties with which we contract.

An increase ininterest rates could result in a significant increase in the amount we pay toservice debt, resulting in a decrease in distributions to Unitholders, as wellas negatively impact the market price of the Trust Units.

**Proposed Federal Tax Changes**

On October 31, 2006 the Federal Minister of Finance proposed toapply a tax at the trust level on distributions of certain income from publiclytraded mutual fund trusts at rates of tax comparable to the combined federaland provincial corporate tax and to treat such distributions as dividends tothe unitholders (the “October 31 Proposals”). On December 21, 2006 the Federal Minister of Finance released draftlegislation to implement the October 31, 2006 Proposals pursuant to which,commencing January 1, 2011 (provided Penn West only experiences “normalgrowth” and no “undue expansion” before then) certain distributions from uswhich would have otherwise been taxed as ordinary income generally will becharacterized as dividends to the Unitholders and will be subject to tax at thecorporate rates at the Trust level. Assuming the October 31 Proposals are ultimately enacted in theircurrent form, the implementation of such legislation would be expected toresult in adverse tax consequences to us and certain Unitholders (includingmost particularly Unitholders that are tax deferred or non-residents of Canada)and may impact the level of cash distributions from us.

Management believes that the October 31 Proposals may reduce thevalue of the Trust Units, which would be expected to increase the cost to PennWest of raising capital in the public capital markets.  In addition, management believes that theOctober 31 Proposals are expected to: (a) substantially eliminate anycompetitive advantage that Penn West and other Canadian energy trusts enjoyrelative to their corporate peers in raising capital in a tax-efficient manner;and (b) place Penn West and other Canadian energy trusts at a competitivedisadvantage relative to industry competitors, including U.S. master limitedpartnerships, which will continue to not be subject to entity level taxation.  The October 31 Proposals are alsoexpected to make the Trust Units less attractive as consideration foracquisitions.  As a result, it may becomemore difficult for us to compete effectively for acquisition opportunities.  There can be no assurance that we will beable to reorganize our legal and tax structure to substantially mitigate theexpected impact of the October 31 Proposals.

Further, the proposals provide that, while there is no intention toprevent “normal growth” during the transitional period, any “undue expansion”could result in the transition period being “revisited”, presumably with theloss of the benefit to us of that transitional period.  As a result, the adverse tax consequencesresulting from the proposals could be borne sooner than 

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January 1, 2011.  OnDecember 15, 2006, the Department of Finance issued guidelines withrespect to what is meant by “normal growth” in this context.  Specifically, the Department of Financestated that “normal growth” would include equity growth within certain “safeharbour” limits, measured by reference to a “specified investment flow-through’s”(“SIFT”) market capitalization as of the end of trading on October 31,2006 (which would include only the market value of the SIFT’s issued andoutstanding publicly-traded trust units, and not any convertible debt, optionsor other interests 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:

(a)                                  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);

(b)                                 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

(c)                                  the exchange, for trust units, ofexchangeable partnership 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.

Our market capitalization as of the close of trading onOctober 31, 2006, having regard only to our issued and outstandingpublicly-traded Trust Units, was approximately $9.987 billion, which means our “safeharbour” equity growth amount for the period ending December 31, 2007 isapproximately $3.996 billion, and for each of calendar year 2008, 2009 and 2010is an additional approximately $1.998 billion (in any case, not includingequity, including convertible debentures, issued to replace debt that wasoutstanding on October 31, 2006).

While these guidelines are such that it is unlikely they would affectour ability to raise the capital required to maintain and grow our existingoperations in the ordinary course during the transition period, they couldadversely affect the cost of raising capital and our ability to undertake moresignificant acquisitions.

The Government of Canada confirmed its intention to proceed with theOctober 31 Proposals, subject to any modifications to take into account consultationsand deliberations, in its budget speech of March 19, 2007.

**It is not known at this time when the October 31Proposals will be enacted by Parliament, if at all, or whether theOctober 31 Proposals will be enacted in the form currently proposed or newproposals will be proposed or enacted. See “Risk Factors — Changes in Legislation”.**

**Reserve Estimates**

There are numerousuncertainties inherent in estimating quantities of oil, natural gas and NGLsreserves and cash flows to be derived therefrom, including many factors beyondour control.  The reserve and associatedcash flow information set forth in this Annual Information Form representsestimates only.  In general, estimates ofeconomically recoverable oil and natural gas reserves and the future net cashflows therefrom are based upon a number of variable factors and assumptions,such as historical production from the properties, production rates, ultimatereserve recovery, timing and amount of capital expenditures, marketability ofoil and natural gas, royalty rates, the assumed effects of regulation bygovernmental agencies and future operating costs, all of which may vary fromactual results.  All such estimates areto some degree speculative, and classifications of reserves are attempts todefine the degree of speculation involved. For those reasons, estimates of the economically recoverable oil andnatural gas reserves attributable to any particular group of properties,classification of such reserves based on risk of recovery and estimates offuture net revenues expected therefrom prepared by different engineers, or bythe same engineers at different times, may vary.  Our actual production, revenues anddevelopment and operating expenditures will vary from reserve estimates thereofand such variations could be material.

Estimates ofproved reserves that may be developed and produced in the future are sometimesbased upon volumetric calculations and upon analogy to similar types ofreserves rather than 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.

 

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In accordance withapplicable securities laws, GLJ has used both constant and forecast price andcost estimates in calculating reserve quantities included in this AnnualInformation Form.  Actual future net cashflows will be affected by other factors including but not limited to actualproduction levels, supply and demand for oil and natural gas, curtailments orincreases in consumption by oil and natural gas purchasers, changes ingovernmental regulation or taxation and the impact of inflation on costs.

Actual production andcash flows derived from reserves will vary from the reserves estimatescontained in the engineering reports summarized in this Annual InformationForm, and such variations could be material. The GLJ Report is based in part on the assumed success of activities weintend to undertake in future years.  Thereserves and estimated cash flows to be derived therefrom contained in theengineering reports summarized in this Annual Information Form will be reduced,in future years, to the extent that such activities do not achieve the level ofsuccess assumed in the engineering reports summarized in this AnnualInformation Form.

**Depletion of Reserves**

Distributions of incomefrom our properties, 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 cash flow to Unitholders, we will not be reinvesting cash flowin the same manner as some other industry participants and will only conductlimited exploratory activities as one of our main objectives is to maximizelong-term distributions.  Accordingly,absent capital injections, our initial production levels and reserves willdecline over time and, absent changes to other factors, the level of incomeavailable for distributions will also decline over time.

Our future oil andnatural gas reserves and production, and therefore our cash flows, will behighly dependent on our success in exploring and exploiting our reserve andland base and 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 thatexternal sources of capital, including the issuance of additional Trust Unitsbecome limited or unavailable, our ability to make the necessary capitalinvestments to maintain or expand our oil and natural gas reserves will beimpaired.  To the extent that we arerequired to use higher proportions of cash flow to finance capital expendituresor property acquisitions, the level of cash flow available for distributionswill be reduced.

There can be no assurancethat we will be successful in developing or acquiring additional reserves onterms that meet our investment objectives.

**Changes in Legislation**

Income tax laws, or otherlaws or government incentive programs relating to the oil and gas industry,such as the treatment of mutual fund trusts and resource taxation, may in thefuture be changed or interpreted in a manner that adversely affects us and ourUnitholders.  Tax authorities havingjurisdiction over us or the Unitholders may disagree with how we calculate ourincome for tax purposes or could change administrative practises to ourdetriment or the detriment of our Unitholders.

We intend to continue toqualify as a mutual fund trust for purposes of the *Income Tax Act* (Canada). We may not, however, always be able to satisfy any future requirementsfor the maintenance of mutual fund trust status.  Should our status as a mutual fund trust belost or successfully challenged by a relevant tax authority, certain adverseconsequences may arise for us and our Unitholders.  Some of the significant consequences oflosing mutual fund trust status are as follows:

·                  Wewould be taxed on certain types of income distributed to Unitholders, includingincome generated by the royalties we hold. Payment of this tax may have adverse consequences for some Unitholders,particularly Unitholders that are not residents of Canada and residents ofCanada that are otherwise exempt from Canadian income tax or hold their unitsin a tax deferred account.

·                  Wewould cease to be eligible for the capital gains refund mechanism availableunder Canadian tax laws if we ceased to be a mutual fund trust.

·                  TrustUnits held by Unitholders that are not residents of Canada would become taxableCanadian property.  These non-residentholders would be subject to Canadian income tax on any gains realized on adisposition of Trust Units held by them.

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·                  TrustUnits would not constitute qualified investments for registered retirementsavings plans (“RRSPs”), registered retirement income funds (“RRIFs”),registered education savings plans (“RESPs”) or deferred profit sharingplans.  If, at the end of any month, oneof these exempt plans holds Trust Units that are not qualified investments, theplan must pay a tax equal to one percent of the fair market value of the TrustUnits at the time the Trust Units were acquired by the exempt plan.  An RRSP or RRIF holding non-qualified TrustUnits would be subject to taxation on income attributable to the TrustUnits.  If an RESP holds non-qualifiedTrust Units, it may have its registration revoked by the Canada Revenue Agency.

In addition, we may takecertain measures in the future to the extent we believe necessary to ensurethat we maintain our status as a mutual fund trust.  These measures could be adverse to certainholders of Trust Units, particularly “non-residents” of Canada as defined inthe *Income Tax Act* (Canada).

On February 16,2007, the Alberta government began a review of Alberta’s royalty regime for oilsands, conventional oil and gas and coalbed methane to assess whether theexisting royalty regime is providing Albertans with a fair return on theprovince’s natural resources while maintaining an internationally competitivesystem that allows the Alberta economy to continue to prosper.  The review, expected to be completed byAugust 31, 2007, may result in recommendations which could adverselyimpact the current royalty structure in place for our economics for our coalbedmethane prospects.  For more information,see “Risk Factors — Non-resident Ownership of Trust Units”, “Risk Factors —Proposed Federal Tax Changes”, “Risk Factors — Environmental Concerns” and “RiskFactors — Kyoto Protocol”.

**Environmental**

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 and facility sites be operated,maintained, abandoned and reclaimed to the satisfaction of applicableregulatory authorities.  Compliance withsuch legislation can require significant expenditures and a breach may resultin the imposition of fines and penalties, some of which may be material.  Environmental legislation is evolving in amanner expected to result in stricter standards and enforcement, larger finesand liability and potentially increased capital expenditures and operatingcosts.  The discharge of oil, natural gasor other pollutants into the air, soil or water may give rise to liabilities togovernments and third parties and may require our operating entities to incurcosts to remedy such discharge. Furthermore, management believes the political climate appears to favournew programs for environmental laws and regulation, particularly in relation tothe reduction of emissions, and there is no assurance that any such programs,laws or regulations, if proposed and enacted, will not contain emissionreduction targets which we cannot meet, and financial penalties or chargescould be incurred as a result of the failure to meet such targets.  In particular there is uncertainty regardingthe Government of Canada’s Clean Air Act of 2006.  The Clean Air Act proposes to reducegreenhouse gas emissions, however emission targets and compliance deadlinesdiffer from those outlined in the Kyoto Protocol which was ratified byCanada.  If passed, the Clean Air Act mayhave adverse operational and financial implications to the Trust.  Provincial emission reduction requirements,such as those proposed in Alberta’s Bill 37 Climate Change and EmissionsManagement, may require the reduction of emissions or emissions intensity ofour operations and facilities.  Thedirect or indirect costs of these regulations may adversely and materiallyaffect our business.  Although we believethat we are in material compliance with current applicable environmentalregulations, no assurance can be given that environmental laws will not resultin a curtailment of production or a material increase in the costs ofproduction, development or exploration activities or otherwise adversely affectour financial condition, results of operations or prospects.  Future changes in other environmentallegislation could occur and result in stricter standards and enforcement,larger fines and liability, and increased capital expenditures and operatingcosts, which could have a material adverse effect on our financial condition orresults of operations.  See “IndustryConditions — Environmental Regulation”.

**Kyoto Protocol**

Canada is a signatory tothe United Nations Framework Convention on Climate Change and has ratified theKyoto Protocol established thereunder to set legally binding targets to reducenationwide emissions of carbon dioxide, methane, nitrous oxide and other so-called“greenhouse natural gases”.  Ourexploration and production facilities and other operations and activities emita small amount of greenhouse natural gases which may subject us to legislationregulating emissions of greenhouse natural gases.  The Government of Canada has put forward aClimate Change Plan for Canada that suggests further legislation will setgreenhouse natural gases emission reduction requirements for various industrialactivities, including oil and natural gas exploration and production.  While the protocol became legally binding onFebruary 16, 2005, details of any specific requirements have not been releasedand as a result the potential impact on our operations and business isdifficult to quantify.  See “IndustryConditions — Environmental Regulation”.

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**Resource Plays — Enhanced Oil Recovery**

We currently useconventional artificial lift technology to recover heavy oil from bitumendeposits at our Peace River Oil Sands project. The potential or planned use of enhanced oil recovery (“EOR”) methodssuch as steam injection (Steam Assisted Gravity Drainage and Cyclical SteamStimulation), solvent injection and firefloods to increase the ultimaterecovery of oil resources in place are subject to significant riskfactors.  These factors, which could leadto delayed or cancelled EOR application in the Peace River Oil Sands projectinclude but are not limited to the following: (i) changing economicconditions (commodity pricing, operating and capital expenditure fluctuations);(ii) changing engineering and technical conditions (ability to apply EORmethods to the reservoir and the production response thereto); (iii) thelarge development program may need to spread over a longer time period thaninitially planned due to requirement to allocate capital expenditures todifferent periods; (iv) surface access and deliverability issues (FirstNations relations, weather, pipeline, road and processing matters); and(v) financing (the availability of sufficient financing on acceptableterms).

The use or potential orplanned use of CO2 miscibleflooding to increase the oil recovery from large legacy oil pools such asPembina, South Swan Hills and Midale is subject to significant risk factorswhich could lead to the delay or cancellation of some or all of theseprojects.  These factors include but arenot limited to: (i) CO2 infrastructure(the capture and transportation of the miscible agent to us at an economiccost); (ii) changing economic conditions (commodity pricing, operating andcapital expenditure fluctuations); (iii) changing engineering andtechnical conditions (ability to apply CO2 EOR methods to the reservoir and the productionresponse thereto); (iv) the large development program may need to bespread over a longer time period than planned due to capital allocationrequirements; (v) surface access and deliverability issues (weather,pipeline, road and processing matters); and (vi) financing (theavailability of sufficient financing on acceptable terms).

**Coalbed Methane Projects (“CBM”)**

The engineering,geological, production and associated dewatering techniques are relatively newand their application to our CBM prone properties is subject to these risks inaddition to risk factors similar to those listed in the preceding paragraphsrelated to the Peace River Oil Sands and CO2 miscible flooding.

**Additional Financing**

In the normal course ofmaking capital investments to maintain and expand our oil and gas reserves,additional Trust Units may be issued which may result in a decline inproduction per Trust Unit and reserves per Trust Unit.  Additionally, from time to time, we may issueTrust Units from treasury in order to reduce debt and maintain a more optimalcapital structure.  Conversely, to theextent that external sources of capital, including the issuance of additionalTrust Units becomes limited or unavailable, our ability to make the necessarycapital investments to maintain or expand our oil and gas reserves will beimpaired.  Management believes that theOctober 31 Proposals of the Government of Canada are expected to substantiallyeliminate the competitive advantage that we and other energy trusts enjoyrelative to their industry competitors in raising capital in a tax-efficientmanner.  See “Risk Factors — ProposedFederal Tax Changes”.  To the extent thatwe are required to use additional cash flow to finance capital expenditures orproperty acquisitions or to pay debt service charges or to reduce debt, thelevel of cash flow for distributions will be reduced.

**Competition**

There is strongcompetition relating 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 acquisitions of properties with longer life reserves andproperties with exploitation and development opportunities.  The October 31 Proposals of the Government ofCanada are expected by management to make our Trust Units less attractive asconsideration for acquisitions.  See “RiskFactors — Proposed Federal Tax Changes”. As a result of such increasing competition, it is expected to becomemore difficult to acquire producing assets and reserves on beneficialterms.  We also compete for skilledindustry personnel with a substantial number of other oil and gas companies andtrusts.

**Non-Resident Ownership of Trust Units**

In order for us tomaintain our status as a mutual fund trust under the *Income Tax Act*(Canada), we must not be established ormaintained primarily for the benefit of non-residents of Canada (“non-residents”)within the meaning of the *Income Tax Act*(Canada).The Trust Indenture provides that the Trust will use its best commercialefforts to maintain its status as a mutual fund trust under the *Income Tax Act* (Canada).  See “Information Relating to the Trust —Trust Indenture — Limitations on Non-Resident Ownership”.  Generally speaking, the *Income Tax Act* (Canada) provides that atrust will permanently lose its

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“mutual fund trust”status (which is essential to the income trust structure) if it is establishedor maintained primarily for the benefit of non-residents of Canada (which isgenerally interpreted to mean that the majority of unitholders must not benon-residents of Canada), unless at all times after February 21, 1990, “all orsubstantially all” of the trust’s property consisted of property other thantaxable Canadian property (the “TCP Exception”).  Based on the most recent information obtainedby Penn West through its transfer agent and financial intermediaries, inFebruary 2007, we have estimated that in excess of 50% of the Trust’s issuedand outstanding Trust Units were held by non-residents of Canada (as defined inthe *Income Tax Act* (Canada)) atthat time.  The Trust has determined thatit currently meets the requirement of the TCP Exception, and as a result, theTrust Indenture does not currently have a specific limit on the percentage ofTrust Units that may be owned by non-residents.

There is no assurancethat the TCP Exception will continue to be available to the Trust or that theGovernment of Canada will not introduce new changes or proposals to taxregulations directed at non-resident ownership which, given the Trust’s levelof non-resident ownership, may result in the Trust losing its mutual fund truststatus or could otherwise detrimentally affect Penn West and the market priceof the Trust Units.  Penn West PetroleumLtd. intends to continue to take the necessary measures in order to ensure theTrust continues to qualify as a mutual fund trust under the *Income Tax Act* (Canada), as it currentlyexists.  See “Risk Factors — Changes in Legislation”.

**Debt Service**

Amounts paid in respectof interest and principal on debt we have incurred will reduce funds availablefor distributions. 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 credit facilities will be sufficient for ourimmediate requirements, there can be no assurance that the amount will beadequate for our future financial obligations or that additional funds will beable to be obtained.

Our current creditagreement is unsecured and we must comply with certain financial debtcovenants.  The lenders could, in thefuture, be provided with security over substantially all of our assets.  In that event if we become unable to pay ourdebt service charges or otherwise commit an event of default such asbankruptcy, the lender may foreclose on or sell our oil and gas and otherassets.

**Asset Write-Downs**

Canadian GenerallyAccepted Accounting Principles (“GAAP”) require that management apply certainaccounting policies and make certain estimates and assumptions that affectreported amounts in our consolidated financial statements.

Under 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 cash flows from reserves. Ifnet capitalized costs exceed the estimated recoverable amounts, we will have tocharge the amount of the excess to net income. A decline in the net value of oil and natural gas properties could causecapitalized costs to exceed the cost ceiling, resulting in a charge againstearnings.  The value of oil and gasproperties is highly dependent upon the prices of oil and natural gas.  Under United States GAAP, the estimatedrecoverable amounts are calculated based on estimated future net cash 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”.

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 at December 31, 2006 we had $652million recorded on our balance sheet as goodwill arising out of the PetrofundMerger.  An impairment would result in awrite-down of the goodwill value and a non-cash charge against net income. Thecalculation of impairment value is subject to management estimates andassumptions.

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.

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**Regulatory**

Oil and natural gasoperations (exploration, production, pricing, marketing and transportation) aresubject to extensive controls and regulations imposed by various levels ofgovernment that may be amended from time to time.  See “Industry Conditions”.  Our operations may require licenses fromvarious governmental authorities.  Therecan be no assurance that we will be able to obtain all necessary licenses andpermits that may be required to carry out exploration and development at ourprojects.

**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 unexpected formations or pressures, prematuredeclines of reservoirs, blow-outs, equipment failures and other accidents, sourgas releases, uncontrollable flows of oil, natural gas or well fluids, adverseweather conditions, pollution, other environmental risks, fires andspills.  Although we maintain insurancein accordance with customary industry practice, 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 productionfrom a property, and to some extent the marketing of production therefrom, arelargely dependent upon 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.

**Insurance**

Our involvement in theexploration for and development of oil and natural gas properties could subjectPenn West to liability for pollution, blowouts, property damage, personalinjury or other hazards.  Prior tocommencing operations our operating entities obtain insurance in accordancewith industry standards to address certain of these risks.  Such insurance has limitations on liabilitythat may not be sufficient to cover the full extent of such liabilities.  In addition, such risks may not, in allcircumstances, be insurable or, in certain circumstances, our operatingentities may elect not to obtain insurance to deal with specific risks due tothe high premiums associated with such insurance or other reasons. The paymentof such uninsured liabilities would reduce the funds available to us. Theoccurrence of a significant event that we are not fully insured against, or theinsolvency of the insurer of such event, could have a material adverse effecton our financial position, results of operations or prospects and will reducecash flow otherwise distributable by us.

**Maintenance of Distributions**

Future oil and naturalgas reserves and hence revenues are highly dependent on our operating entities’success in exploiting existing properties and acquiring additionalreserves.  We also distributeapproximately 60 percent to 70 percent of our net cash flow to Unitholdersrather than reinvesting it in reserve additions.  Accordingly, if external sources of capital,including the issuance of additional Trust Units, become limited or unavailableon commercially reasonable terms, our operating entities’ ability to make thenecessary capital investments to maintain or expand their oil and natural gasreserves will be impaired.  To the extentthat our operating entities are required to use cash flow to finance capitalexpenditures or property acquisitions, the level of cash flow available fordistribution to Unitholders will be reduced. Additionally, we cannot guarantee that we will be successful inexploring for and developing additional reserves or acquiring additionalreserves on terms that meet our investment objectives.  Without these reserve additions, our reserveswill deplete and as a consequence, either production from, or the averagereserve life of, our properties will decline. Either decline may result in areduction in the value of Trust Units and in a reduction in cash available fordistributions to Unitholders.

**Delay in Cash Distributions**

In addition to the usualdelays in 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

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accidents, recovery bythe operator of expenses incurred in the operation of properties or theestablishment by the operator of reserves for such expenses.

**Reliance on Management**

Unitholders will bedependent on the management of Penn West Petroleum Ltd. in respect of theadministration and management of all matters relating to our operations.  Penn West Petroleum Ltd., as ofDecember 31, 2006, operated approximately 70 percent of our total dailyproduction.  Investors who are notwilling to rely on the management of Penn West Petroleum Ltd. should not investin the Trust Units, or any future issuance of exchangeable shares and/orconvertible debentures.

**Expansion of Operations**

The operations andexpertise of management are currently focused on conventional oil and gasproduction and exploration and development in the Western Canadian SedimentaryBasin.  In the future, we may acquire oiland gas properties outside this geographic area.  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, upgrades 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.

**Net Asset Value**

Our net asset value fromtime to time 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.

**Return of Capital**

Trust Units will have novalue when 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 alimited right to require us to repurchase their Trust Units, which is referredto as a redemption 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.

**Natureof Trust Units**

The Trust Units do notrepresent a traditional investment in the oil and natural gas sector and shouldnot be viewed by investors as shares in Penn West Petroleum Ltd. The TrustUnits represent a fractional interest in our assets. As holders of Trust Units,Unitholders will not have the statutory rights normally associated withownership of shares of a corporation including, for example, the right to bring“oppression” or “derivative” actions. The rights of Unitholders are specifically set forth in the TrustIndenture.  In addition, trusts are notdefined as recognized entities within the definitions of legislation such asthe *Bankruptcy and Insolvency Act*(Canada), the *Companies’ CreditorsArrangement 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 Notes. Theprice per Trust Unit is a function of anticipated income available fordistributions, the oil and gas assets acquired by us and our ability to effectlong-term growth in the value of our assets. The market price of the Trust Units will be sensitive to a variety ofmarket conditions including, but not limited to, interest rates and our abilityto acquire suitable oil and natural gas properties. Changes in marketconditions may adversely affect the trading price of the Trust Units.

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**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 company and,accordingly, the Trust is not registered under any trust and loan companylegislation as it does not carry on or intend to carry on the business of atrust company.**

**Unitholder Limited Liability**

The Trust Indentureprovides that no Unitholder will be subject to any liability in connection withour obligations and affairs and, in the event that a court determinesUnitholders are subject to any such liabilities, the liabilities will beenforceable only against, and will be satisfied only out of our assets.Pursuant to the Trust Indenture, we will indemnify and hold harmless eachUnitholder from any costs, damages, liabilities, expenses, charges and lossessuffered by a Unitholder resulting from or arising out of such Unitholder nothaving such limited liability.

The Trust Indentureprovides that 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.

**MATERIALCONTRACTS**

Except for contractsentered into in the ordinary course of business, the only material contractsentered into by us within the most recently completed financial year, or beforethe most recently completed financial year but are still material and are stillin effect, are the following:

(a)                                  theTrust Indenture;

(b)                                 theAdministration Agreement; and

(c)                                  theNPI Agreements.

Copies of each of thesedocuments have been filed on SEDAR at www.sedar.com.

**TRANSFERAGENT AND REGISTRAR**

The transfer agent andregistrar for the Trust Units is CIBC Mellon Trust Company at its principaloffices in Calgary, Alberta.

**INTERESTOF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS**

There were no materialinterests, direct or indirect, of directors and senior officers of Penn WestPetroleum Ltd., any holder of Trust Units who beneficially owns more than 10percent of the outstanding Trust Units, or any known associate or affiliate ofsuch persons, in any transaction within the three most recently completedfinancial years which has materially affected or would materially affect usexcept for the matter disclosed in Note 17 under the heading “Related partytransactions” of the consolidated financial statements for the years ending2006 and 2005 which note is incorporated by reference in this AnnualInformation Form and which is filed on SEDAR at www.sedar.com.

**INTERESTSOF EXPERTS**

There is no person orcompany whose profession or business gives authority to a statement made bysuch person or company and who is named as having prepared or certified astatement, report or valuation described or included in a filing, or referredto in a filing, made under National Instrument 51-102 by us during, or relatedto, our most recently completed financial year other than GLJ, our independentengineering evaluator, and KPMG LLP, our auditors.  As at the date hereof the designatedprofessionals of GLJ Petroleum Consultants Ltd., as a group, beneficiallyowned, directly or indirectly, less than 1 per cent of our outstanding securities,including the securities of our associates and affiliates.  KPMG LLP is the auditor of the Trust and isindependent within the meaning of the Rules of Professional Conduct of theInstitute of Chartered Accountants, Alberta.

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In addition, none of theaforementioned persons or companies, nor any director, officer or employee ofany of the aforementioned persons or companies, is or is expected to beelected, appointed or employed as a director, officer or employee of Penn WestPetroleum Ltd. or of any of our associate or affiliate entities**.** John A. Brussa, the Chairman of Penn WestPetroleum Ltd., is a partner at Burnet, Duckworth & Palmer LLP, a law firmwhich renders legal services to us.

**ADDITIONAL INFORMATION**

Additionalinformation including remuneration of directors and officers of Penn WestPetroleum Ltd., principal holders of the Trust Units and rights to purchaseTrust Units, will be contained in the Information Circular which relates to theAnnual Meeting of Unitholders to be held on June 8, 2007, and additionalfinancial information is provided in our consolidated financial statements andmanagement discussion and analysis of financial results for the year endedDecember 31, 2006 which have been filed on SEDAR at *www.sedar.com*.

 

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**APPENDIXA**

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

**(Form51-101F3)**

Management of Penn WestPetroleum Ltd. on behalf of Penn West 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 consist of thefollowing:
|        | (a)    | (i)    | proved and proved plus probable oil and gas reserves  estimated as at December 31, 2006 using forecast prices and costs; and |
|--------|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------|
|   |   |   |                                                                                                                              |
|   |   | (ii)   | the related estimated future net revenue; and                                                                                     |
|   |   |   |                                                                                                                              |
|   | (b)    | (i)    | proved oil and gas reserves estimated as at December  31, 2006 using constant prices and costs; and                               |
|   |   |   |                                                                                                                              |
|   |   | (ii)   | the related estimated future net revenue.                                                                                         |

 

 

An independent qualifiedreserves evaluator has evaluated Penn West’s reserves data. The report of theindependent qualified reserves evaluator is presented below.

The Reserves Committee ofthe Board of Directors has:
|        | (a)    | reviewed Penn West’s procedures for providing  information to the independent qualified reserves evaluator;                                                                                      |
|--------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                  |   |
|   | (b)    | met with the independent qualified reserves  evaluator to determine whether any restrictions affected the ability of the  independent qualified reserves evaluator to report without reservation; and |
|   |   |                                                                                                                                                                                                  |   |
|   | (c)    | reviewed the reserves data with management and the  independent qualified reserves evaluator.                                                                                                         |

 

The Reserves Committee ofthe Board of Directors has reviewed Penn West’s procedures for assembling andreporting other information associated with oil and gas activities and hasreviewed that information with management. The Board of Directors has, on therecommendation of the Reserves Committee, approved:
|        | (a)    | the content and filing with securities regulatory  authorities of the reserves data and other oil and gas information; |
|--------|--------|------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                   |
|   | (b)    | the filing of the report of the independent  qualified reserves evaluator on the reserves data; and                    |
|   |   |                                                                                                                   |
|   | (c)    | the content and filing of this report.                                                                                 |

 

Because the reserves dataare based on judgments regarding future events, actual results will vary andthe variations may be material.
| /s/ William E. Andrew                             |   | /s/ David Middleton                                  |
|---------------------------------------------------|--------|------------------------------------------------------|
| President and  Chief Executive Officer            |   | Executive Vice President and Chief Operating Officer |
|                                              |   |                                                 |
| /s/ Murray Nunns                                  |   | /s/ Thomas E. Philips                                |
| Director and  Chairman of the Reserves  Committee |   | Director and Member of the Reserves Committee        |
|                                              |   |
| March 22,  2007                              |   |

 

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**APPENDIXB**

**GLJREPORT ON RESERVES DATA**

**(Form51-101 F2)**

To the Board of Directorsof Penn West Petroleum Ltd. on behalf of Penn West Energy Trust (collectively “PennWest”):

1.                                       We have evaluated Penn West’s reservesdata as at December 31, 2006.  Thereserves data consist of the following:

 

(a)                           (i)             proved and proved plus probable oiland gas reserves estimated as at December 31, 2006 using forecast prices andcosts; and

 

                                         (ii)            therelated estimated future net revenue; and

 

(b)                          (i)             provedoil and gas reserves estimated as at December 31, 2006 using constantprices and costs; and

 

                                         (ii)            therelated estimated future net revenue.                                                                    

 

2.                                       The reserves data are the responsibilityof Penn West’s management.  Our responsibilityis to express an opinion on the reserves data based on our evaluation.

We carried out our evaluation in accordance with standards set out inthe Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) preparedjointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) andthe Canadian Institute of Mining, Metallurgy & Petroleum (PetroleumSociety).

3.                                       Those standards require that we plan andperform an evaluation to obtain reasonable assurance as to whether the reservesdata are free of material misstatement. An evaluation also includes assessing whether the reserves data are inaccordance with principles and definitions presented in the COGE Handbook.

4.                                       The following table sets forth theestimated future net revenue (before deduction of income taxes) attributed toproved 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 and reviewed by us for the year ended December 31,2006, and identifies the respective portions thereof that we have audited,evaluated and reviewed and reported on to Penn West’s Board of Directors:
| ** **                                                               | ** ** | **Description**                      | ** ** | ** **                     | ** ** | **Net Present Value of Future Net Revenue** | ** ** |
|--------------------------------------------------------------------------|------------|--------------------------------------|------------|--------------------------------|------------|---------------------------------------------------------------------------|------------|
| ** **                                                               | ** ** | **and**                              | ** ** | ** **                     | ** ** | **(millions before income taxes, **                   | ** ** |
| ** **                                                               | ** ** | **Preparation**                      | ** ** | ** **                     | ** ** | **10% discount rate)**                                          | ** ** |
| **Independent Qualified  Reserves Evaluator or  Auditor** | ** ** | **Date of  Evaluation  Report** | ** ** | **Location of  Reserves** | ** ** | **Audited**                                                               | ** ** | **Evaluated** | ** ** | **Reviewed** | ** ** | **Total** | ** ** |
| GLJ Petroleum Consultants Ltd.                                           |       | February 28, 2007               |       | Canada                         |       | nil                                                                       |       | $ | 7,049 |   | nil |   | $ | 7,049 |   |
|                                                                          |            |                                      |            |                                |            |                                                                           |            |  |  |  |  |  |  |  |  |

5.                                       In our opinion, the reserves datarespectively evaluated by us have, in all material respects, been determinedand are in accordance with the COGE Handbook. We express no opinion on the reserves data that we reviewed but did notaudit or evaluate.

6.                                       We have no responsibility to update ourreports referred to in paragraph 4 for events and circumstances occurringafter their respective preparation date.

7.                                       Because the reserves data are based onjudgements regarding future events, actual results will vary and the variationsmay be material.
| /s/ GLJ Petroleum  Consultants Ltd. |   |
|-------------------------------------|--------|
| Calgary, Alberta                    |   |
| February 28,  2007             |   |

 

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**APPENDIXC**

**MANDATEOF THE AUDIT COMMITTEE**

**Role and Objective**

The Audit Committee (the “**Committee**”)is a committee of the board of directors of Penn West Petroleum Ltd. (the “**Company**”), administrator of Penn WestEnergy Trust (the “**Trust**”), towhich the board has delegated its responsibility for oversight of the integrityof the Trust’s consolidated financial statements, the Trust’s compliance withlegal and regulatory requirements, the independent auditor’s qualifications andindependence, and the performance of the Trust’s internal audit function, ifany.  The objectives of the Committee,with respect to Company and the Trust (hereinafter collectively referred to as “**Penn West**”), are as follows:

·                                          To assist theBoard in meeting its responsibilities (especially for accountability) inrespect of the preparation and disclosure of the consolidated financialstatements of the Trust and related matters;

·                                          To providebetter communication between directors and independent auditors;

·                                          To assist theBoard in meeting its responsibilities regarding the oversight of theindependent auditor’s qualifications and independence;

·                                          To assist theBoard in meeting its responsibilities regarding the oversight of thecredibility, integrity and objectivity of financial reports;

·                                          To strengthenthe role of the non-management directors by facilitating discussions betweendirectors on the Committee, management and independent auditors;

·                                          To assist theBoard in meeting its responsibilities regarding the oversight of theperformance of the Company’s independent auditors and internal audit function,if any; and

·                                          To assist theBoard in meeting its responsibilities regarding the oversight of the Company’scompliance with legal and regulatory requirements.

**Mandate and Responsibilities of Committee**

·                                          It is theresponsibility of the Committee to satisfy itself on behalf of the Board thatthe Company’s internal control systems are sufficient to reasonably ensurethat:

·                                          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 primaryresponsibility of the Committee to review the annual and quarterly financialstatements of the Trust prior to their submission to the board of directors forapproval.  The process should include butnot 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 test calculation;

·                                          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;

·                                          obtainingreasonable explanations of significant variances with comparative reportingperiods; and

·                                          determinethrough inquiry if there are any related party transactions and ensure thenature and extent of such transactions are properly disclosed.

·                                          The Committeeis to review, discuss and recommend for approval by the Board the annual andquarterly financial statements and related information included inprospectuses, management discussion and analysis (MD&A), informationcircular-proxy statements and annual information forms (AIF), prior torecommending board approval.

·                                          Discuss theTrust’s quarterly results press releases, as well as financial information andearnings guidance provided to analysts and rating agencies (provided that theCommittee is not required to review and discuss investor presentations that donot contain financial information or earnings guidance that has not previouslybeen generally disclosed to the public).

·                                          With respect tothe appointment of independent auditors 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, theCommittee will ensure the rotation of partners on the audit engagement team inaccordance with applicable law and, in order to ensure continuing auditorindependence, consider the rotation of the audit 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 andreviewing the report by the independent auditors describing the independentauditors’ internal quality control procedures, any material issues raised bythe most recent interim quality-control review, or peer review, of theindependent auditors, or by any inquiry or 

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investigation bygovernmental or professional authorities, within the preceding five years,respecting one or more independent audits carried out by the independentauditors, 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 Committeeshall also review annually with the independent auditors their plan for theiraudit and, upon completion of the audit, their reports upon the financialstatements of Penn West and its subsidiaries.

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

·                                          Obtainassurance from the independent auditors that disclosure to the Committee is notrequired pursuant to the provisions of the United States Securities ExchangeAct of 1934, as amended, regarding the discovery by the independent auditors ofillegal acts.

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

·                                          the pre-approval policies and proceduresare detailed as to the particular service;

·                                          the Committee is informed of eachnon-audit service so approved; and

·                                          the procedures do not include delegationof the Committee’s responsibilities to management.

·                                          The Committeewill satisfy the pre-approval requirement set forth in the above paragraph if:

·                                          the aggregate amount of all non auditservices that were not pre approved is reasonably expected to constitute nomore than 5% of the total amount of fees paid by the Trust and its subsidiaryentities to the auditors during the fiscal year in which the services areprovided;

·                                          the Trust or the subsidiary entity, asthe case may be, did not recognize the services as non-audit services at thetime of the engagement;

·                                          the services are promptly brought to theattention of the Committee and approved, prior to completion of the audit, bythe Committee or by one or more of its members to whom authority to grant suchapprovals has been delegated by the Committee; and

·                                          Review, set and approve hiring policiesrelating to current and former staff of current and former independentauditors.

·                                          Review allpublic disclosure containing financial information before release (providedthat the Committee is not required to review investor presentations that do notcontain financial information or earnings guidance that has not previously beengenerally disclosed to the public).

·                                          Review allpending litigation to ensure disclosures are sufficient and appropriate.

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·                                          Satisfy itselfthat adequate procedures are in place for the review of the Trust’s publicdisclosure of financial information from the Trust’s financial statements andperiodically assess the adequacy of those procedures.

·                                          Review anddiscuss major financial risk exposures and the steps management has taken tomonitor and control such exposures. Discuss guidelines and policies to govern the process by which riskassessment and management is undertaken.

·                                          Establishprocedures independent of management for:

·                                          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 anyother matters required by law, regulation or stock exchange requirement, orthat the Committee feels are important to its mandate or that the Board choosesto delegate to it.

·                                          Establish,review and update periodically a Code of Business Conduct and Ethics and theCode of Conduct for Senior Officers and Senior Financial Management and ensurethat management has established systems to enforce these codes.

·                                          Reviewmanagement’s monitoring of the Trust’s compliance with the organization’s Codeof Business Conduct and Ethics and the Code of Conduct for Senior Officers andSenior Financial Management.

·                                          Review anddiscuss with the CEO, the CFO and the independent auditors, the mattersrequired to be reviewed with those persons in connection with any certificatesrequired by applicable laws, regulations or stock exchange requirements to beprovided by the CEO and CFO.

·                                          Review anddiscuss major issues regarding accounting principles and financial statementpresentations, including any significant changes in the Trust’s selection orapplication of accounting principles.

·                                          Review anddiscuss major issues as to the adequacy of the Trust’s internal controls andany special audit steps adopted in light of material control deficiencies.

·                                          Review anddiscuss analyses prepared by management and/or the independent auditors settingforth significant financial reporting issues and judgments made in connectionwith the preparation of the financial statements, including analyses of theeffects of alternative generally accepted accounting principles methods on thefinancial statements.

·                                          Review anddiscuss the effect of regulatory and accounting initiatives, as well asoff-balance sheet structures, on the Trust’s financial statements.

·                                          Review anddiscuss the type and presentation of information to be included in earningspress releases, paying particular attention to any use of “pro forma” or “adjusted”non-GAAP information.

**Composition**

·                                          This Committeeshall be composed of at least three individuals appointed by the Board fromamongst its members, all of which members will be independent (within themeaning of (a) Multilateral Instrument 52-110 Audit Committees and (b) Sections303A.02 and 303A.07(b) of the Corporate Governance Rules of the New York StockExchange) unless the Board determines to rely on an exemption in NI 52-110.

·                                          The Secretaryto the Board shall act as Secretary of the Committee.

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·                                          A quorum shallbe a majority of the members of the Committee.

·                                          All of themembers must be financially literate within the meaning of NI 52-110 andSection 303A.07(a) of the Corporate Governance Rules of the New York StockExchange unless the Board has determined to rely on an exemption in NI52-110.  Being “financially literate”means members have the ability to read and understand a set of financialstatements that present a breadth and level of complexity of accounting issuesthat are generally comparable to the breadth and complexity of issues that canreasonably be expected to be raised by the Trust’s financial statements.  In addition, at least one member of the Committee musthave accounting or related financial management expertise, as the Boardinterprets such qualification in its business judgment.

·                                          In connection with the appointment of themembers of the Committee, the Board will determine whether any proposed nomineefor the Committee serves on the audit committee of more than three publiccompanies.  To the extent that anyproposed nominee of PWPL serves on the audit committee of more than threepublic companies, the Board will make a determination as to whether suchsimultaneous services would impair the ability of such member to effectivelyserve on the Company’s Audit Committee and will disclose such determination inthe Trust’s annual information circular and annual report on Form 40-F filedwith the Securities and Exchange Commission.

**Meetings**

·                                          The Committeeshall meet at least four times per year and/or as deemed appropriate by theCommittee Chair.  As part of its job to foster opencommunication, the Committee should meet at least annually with management,internal auditors (if any) and the independent auditors in separate executivesessions to discuss any matters that the Committee or each of these groupsbelieve should be discussed privately. In addition, the Committee or at least its Chair should meet with theindependent auditors and management quarterly to review the Trust’sfinancials.  The Committee should alsomeet with management and independent auditors on an annual basis to review anddiscuss annual financial statements and the management’s discussion andanalysis of financial conditions and results of operations.

·                                          Agendas, withinput from 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 ChiefExecutive Officer and the VP Finance or their designates shall be available toattend at all 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 firstBoard meeting following a Committee meeting, the Committee will provide averbal report to the Board of the material matters discussed and materialresolutions passed at the Committee meeting. The draft minutes of the Committee meeting will subsequently be providedto all Board members as soon as practicable.

·                                          Supportingschedules and information reviewed by the Committee shall be available forexamination by any Director.

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·                                          The Committeeshall have the authority to investigate any financial activity of the Trust andto communicate directly with the internal (if any) and independentauditors.  All employees are to cooperateas requested by the Committee.

·                                          The Committeemay retain, and set and pay the compensation for, persons having specialexpertise and/or obtain independent professional advice, including theengagement of independent counsel and other advisors, to assist in fulfillingits duties and responsibilities at the expense of Penn West.

·                                          The Committeemay delegate any of its duties and responsibilities hereunder to the CommitteeChair or any group of members of the Committee.

·                                          The Committee,in its capacity as a committee of the Board, shall determine appropriatefunding and cause such funding to be available (i) to Penn West’s independentauditors for the purpose of preparing and issuing an audit report, (ii) to anyadvisors employed by the Committee, and (iii) for ordinary administrationexpenses of the Committee that are necessary or appropriate in carrying out itsduties.

 

6

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