d40fa.htm

PENN WEST ENERGY TRUST

Revised Annual Information Form

for the year ended December 31, 2008

March 26, 2009*

*(Except for: (i) page 12 of Appendix A-3, on which the table reflecting (among other things) proved plus probable gross reserves by major operating region as at December 31, 2008 has been revised to correct typographical errors in the allocation of proved plus probable gross reserves among such regions; (ii) Appendix A-1: Report of Management and Directors on Reserves Data and Other Information; and (iii) Appendix A-2: Report on Reserves Data; each of which is dated as of September 15, 2009.)

TABLE OF CONTENTS

	Page

GLOSSARY OF TERMS	3
CONVENTIONS	6
ABBREVIATIONS	6
CONVERSIONS	8
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS	9
NON-GAAP MEASURES	10
EFFECTIVE DATE OF INFORMATION	10
PENN WEST ENERGY TRUST	11
GENERAL DEVELOPMENT OF THE BUSINESS	13
DESCRIPTION OF OUR BUSINESS	18
CAPITALIZATION OF PWPL	18
INFORMATION RELATING TO PENN WEST	20
CORPORATE GOVERNANCE	28
AUDIT COMMITTEE DISCLOSURES	34
DISTRIBUTIONS TO UNITHOLDERS	36
MARKET FOR SECURITIES	36
INDUSTRY CONDITIONS	40
RISK FACTORS	48
MATERIAL CONTRACTS	68
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	68
TRANSFER AGENTS AND REGISTRARS	69
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	69
INTERESTS OF EXPERTS	69
ADDITIONAL INFORMATION	70

APPENDIX "A" – RESERVES DISCLOSURE

Appendix A-1 – Report of Management and Directors on Reserves Data and Other Information

Appendix A-2 – Report on Reserves Data

Appendix A-3 – Statement of Reserves Data and Other Oil and Gas Information

APPENDIX "B" – MANDATE OF THE AUDIT COMMITTEE

GLOSSARY OF TERMS

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

"6.5% 2005 Debenture Indenture" means the trust indenture governing the 6.5% 2005 Debentures.

"6.5% 2005 Debentures" means the 6.5% convertible, extendible, unsecured, subordinated debentures issued on May 26, 2005 pursuant to the 6.5% 2005 Debenture Indenture, which debentures were assumed by Penn West pursuant to the Canetic Acquisition and subsequently began trading on the TSX as securities of Penn West on January 16, 2008 under the symbol PWT.DB.D.

"6.5% 2006 Debenture Indenture" means the trust indenture governing the 6.5% 2006 Debentures.

"6.5% 2006 Debentures" means the 6.5% convertible, extendible, unsecured, subordinated debentures issued on August 24, 2006 pursuant to the 6.5% 2006 Debenture Indenture, which debentures were assumed by Penn West pursuant to the Canetic Acquisition and subsequently began trading on the TSX as securities of Penn West on January 16, 2008 under the symbol PWT.DB.F.

"7.2% Debenture Indenture" means the trust indenture governing the 7.2% Debentures.

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

"8% 2004 Debenture Indenture" means the trust indenture governing the 8% 2004 Debentures.

"8% 2004 Debentures" means the 8% convertible, extendible, unsecured, subordinated debentures issued on June 15, 2004 pursuant to the 8% 2004 Debenture Indenture, which debentures were assumed by Penn West pursuant to the Canetic Acquisition and subsequently began trading on the TSX as securities of Penn West on January 16, 2008 under the symbol PWT.DB.B.

"8% 2005 Debenture Indenture" means the trust indenture governing the 8% 2005 Debentures.

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

"2007 Senior Notes" has the meaning ascribed thereto under "General Development of the Business – History and Development – Year Ended December 31, 2007 – Private Placement of 2007 Senior Notes".

"2008 Senior Notes" has the meaning ascribed thereto under "General Development of the Business – History and Development – Year Ended December 31, 2008 – Private Placement of 2008 Senior Notes".

"2008 Pounds Sterling Senior Notes" has the meaning ascribed thereto under "General Development of the Business – History and Development – Year Ended December 31, 2008 – Private Placement of 2008 Pounds Sterling Senior Notes".

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

"Administration Agreement" means the agreement dated May 31, 2005 between the Trustee and PWPL pursuant to which PWPL agrees to provide certain administrative and advisory services in connection with Penn West.

"Board of Directors" means the Board of Directors of PWPL.

"Canadian GAAP" means Canadian generally accepted accounting principles.

"Canetic" means Canetic Resources Trust, a trust established under the laws of the Province of Alberta.

"Canetic Acquisition" means the plan of arrangement under the ABCA pursuant to which Penn West acquired Canetic on January 11, 2008.

"CBM" means coalbed methane.

"Convertible Debentures" means, collectively, the 6.5% 2005 Debentures, the 6.5% 2006 Debentures, the 7.2% Debentures, the 8% 2004 Debentures and the 8% 2005 Debentures.

"Debenture Indentures" means, collectively, the 6.5% 2005 Debenture Indenture, the 6.5% 2006 Debenture Indenture, the 7.2% Debenture Indenture, the 8% 2004 Debenture Indenture and the 8% 2005 Debenture Indenture.

"Debenture Trustee" means, in respect of the 6.5% 2005 Debentures, Olympia Trust Company, in respect of each of the 6.5% 2006 Debentures and the 8% 2004 Debentures, Computershare Trust Company of Canada, and in respect of each of the 7.2% Debentures and the 8% 2005 Debentures, Canadian Western Trust Company.

"Endev" means Endev Energy Inc., a corporation incorporated under the laws of the Province of Alberta.

"Endev Acquisition" means the plan of arrangement under the ABCA pursuant to which Penn West acquired Endev on July 22, 2008.

"Engineering Reports" means, collectively, the GLJ Report and the Sproule Report.

"Form 40-F" means our Annual Report on Form 40-F for the fiscal year ended December 31, 2008, filed with the SEC.

"GLJ" means GLJ Petroleum Consultants Ltd., independent petroleum consultants of Calgary, Alberta.

"GLJ Report" means the report prepared by GLJ dated February 24, 2009 evaluating approximately 60% of the crude oil, natural gas and natural gas liquids reserves and the net present value of future net revenue attributable to those reserves effective as at December 31, 2008.

"Gross" means:

(a)	in relation to our interest in production or reserves, our working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of ours;

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

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

"Internal Notes" means the unsecured subordinated promissory notes issued by PWPL and certain other Operating Entities to Penn West.

"Net" means:

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

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

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

"NI 51-101" means National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities.

"Non-Resident" means: (i) a person who is not a resident of Canada for the purposes of the Tax Act; or (ii) a partnership that is not a Canadian partnership for the purposes of the Tax Act.

"NPI Agreements" means the net profits interest agreements between Penn West and certain of Penn West's Operating Entities.

"NPIs" means the net profits interests granted to Penn West under the NPI Agreements.

"NYSE" means the New York Stock Exchange.

"Operating Entities" means, collectively, PWPL, Penn West Partnership, Canetic ABC Limited Partnership, Titan Canada Resources, Canetic Resources Partnership, Petrofund Ventures Trust and Upton Resources Inc., each a direct or indirect wholly-owned subsidiary of Penn West as at the date hereof, and "Operating Subsidiary" means any one of them, as applicable.

"Operating Entities Securities" means the Internal Notes, the NPIs, the common shares of PWPL and any other securities of the Operating Entities owned, directly or indirectly, by Penn West.

"Penn West", "we", "us", "our" or "Trust" means Penn West Energy Trust, a trust established under the laws of the Province of Alberta pursuant to the Trust Indenture. Where the context requires, these terms also include all of Penn West's Subsidiaries on a consolidated basis.

"Penn West Partnership" means Penn West Petroleum, a general partnership, the partners of which as at the date hereof are PWPL, Trocana Resources Inc. and Canetic Saskatchewan Trust.

"Petrofund" means Petrofund Energy Trust, a trust established under the laws of the Province of Ontario.

"Petrofund Acquisition" means the plan of arrangement under the ABCA pursuant to which Penn West acquired Petrofund on June 30, 2006.

"PWPL" means Penn West Petroleum Ltd., a corporation amalgamated under the ABCA, a wholly-owned subsidiary of Penn West and the administrator of Penn West pursuant to the Administration Agreement.

"SEC" means the United States Securities and Exchange Commission.

"Sproule" means Sproule Associates Limited, independent petroleum consultants of Calgary, Alberta.

"Sproule Report" means the report prepared by Sproule dated February 26, 2009 evaluating approximately 32% and auditing approximately 8% of the crude oil, natural gas and natural gas liquids reserves and the net present value of future net revenue attributable to those reserves effective as at December 31, 2008.

"Subsidiaries" has the meaning ascribed thereto in the Securities Act (Ontario) and, for greater certainty, includes all corporations, partnerships and trusts owned, controlled or directed, directly or indirectly, by Penn West.

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

"Trust Indenture" means the trust indenture between the Trustee and PWPL, as amended and restated as of June 30, 2006 and as subsequently amended on November 29, 2007.

"Trust Unit" means a trust unit issued by us, each trust unit representing an equal undivided beneficial interest in our assets.

"Trustee" means CIBC Mellon Trust Company, our trustee.

"TSX" means the Toronto Stock Exchange.

"United States" or "U.S." means the United States of America.

"Unitholders" means holders of Penn West Trust Units.

"undeveloped land" and "unproved property" each mean a property or part of a property to which no reserves have been specifically attributed.

"U.S. GAAP" means United States generally accepted accounting principles.

"Vault" means Vault Energy Trust, a trust established under the laws of the Province of Alberta.

"Vault Acquisition" means the plan of arrangement under the ABCA pursuant to which Penn West acquired Vault on January 10, 2008.

CONVENTIONS

Certain terms used herein are defined in the "Glossary of Terms". Certain other terms used herein but not defined herein are defined in NI 51-101 and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101. A discussion of the principal differences between Penn West's financial results calculated under Canadian GAAP and under U.S. GAAP is included in the Form 40-F. On March 26, 2009, the exchange rate for U.S. dollars, expressed in Canadian dollars, based on the noon rate as reported by the Bank of Canada, was Cdn$1.00 equals US$0.8110.

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

All financial information herein has been presented in Canadian dollars in accordance with Canadian GAAP, which differs from U.S. GAAP.

ABBREVIATIONS

Oil and Natural Gas Liquids		Natural Gas

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

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

OIL AND GAS INFORMATION ADVISORIES

Where any disclosure of reserves data is made in this Annual Information Form (including the Appendices hereto) that does not reflect all of the reserves of Penn West, the reader should note that the estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

All production and reserves quantities included in this Annual Information Form (including the Appendices hereto) have been prepared in accordance with Canadian practices and specifically in accordance with NI 51-101. These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the SEC by companies in the United States. See "Risk Factors - Canadian and United States practices differ in reporting reserves and production and our estimates may not be comparable to those of companies in the United States" for a summary of such differences. Nevertheless, as part of the Form 40-F, Penn West has disclosed proved reserves quantities using the standards contained in SEC Regulation S-X, and the standardized measure of discounted future net cash flows relating to proved oil and gas reserves determined in accordance with Statement No. 69 of the U.S. Financial Accounting Standards Board, "Disclosures About Oil and Gas Producing Activities", which disclosure complies with the SEC's rules for disclosing oil and gas reserves.

References in this Annual Information Form to undeveloped land and unproved properties held, owned or acquired by us, or in respect of which we have an interest, refer to undeveloped land or unproved properties in respect of which we have a lease or other contractual right to explore for, develop and exploit hydrocarbons underlying such undeveloped land or unproved properties.

CONVERSIONS

The following table sets forth certain conversions between Standard Imperial Units and the International System of Units (or metric units).

To Convert From	To	Multiply By

Mcf	cubic metres		28.174
cubic metres	cubic feet		35.494
bbl	cubic metres		0.159
cubic metres	bbl		6.293
feet	metres		0.305
metres	feet		3.281
miles	kilometres		1.609
kilometres	miles		0.621
acres	hectares		0.405
hectares	acres		2.500
gigajoules (at standard)	MMbtu		0.950
MMbtu (at standard)	gigajoules		1.053
gigajoules (at standard)	Mcf		1.055

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

In the interest of providing Unitholders and potential investors with information regarding Penn West, including management's assessment of Penn West's future plans and operations, certain statements contained and incorporated by reference in this document constitute forward-looking statements or information (collectively "forward-looking statements") within the meaning of the "safe harbour" provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as "anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "project", "could", "plan", "intend", "should", "believe", "outlook", "potential", "target" and similar words suggesting future events or future performance. In addition, statements relating to "reserves" or "resources" are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future. In particular, this document and the documents incorporated by reference herein contain, without limitation, forward-looking statements pertaining to the following: the performance characteristics of our oil and natural gas properties; the potential impact on our business, business strategies and plans, business model, future growth prospects, distribution policies and Unitholders of the SIFT Tax (as defined herein) and the different actions that we might take in response to the SIFT Tax and the potential impact those actions could have on us and our Unitholders, including without limitation, our potential ability to shield our taxable income from income tax using our tax pools for a period of time following the implementation of the SIFT Tax and the impact this would have on our distributions and Unitholders; the impact that the new Alberta royalty framework may have on us, including on our business strategies and plans; our environmental regulation compliance costs and strategies, the sufficiency of our environmental program and our ability to fund our asset retirement obligations; oil and natural gas production level estimates; our 2009 capital expenditure levels, the timing of making said expenditures, the key elements of our 2009 capital expenditure program and the method of funding said expenditures; our business strategies; our exploration and development plans for our oil and natural gas properties in 2009 and beyond; matters relating to the proposed acquisition of Reece Energy Exploration Corp., including the acquisition metrics, the anticipated benefits of the acquisition and the anticipated impact of the acquisition on our 2009 capital program; funding sources for distributions and distribution levels; the quantity and recoverability of our oil and natural gas reserves and resources; currency exchange rates, inflation rates and interest rates; the nature and effectiveness of our risk management strategies; our outlook for oil and natural gas prices; and our intention and ability to maintain a balanced portfolio of liquids and natural gas production and the benefits we may derive therefrom.

With respect to forward-looking statements contained or incorporated by reference in this document, we have made assumptions regarding, among other things: future capital expenditure levels; future oil and natural gas prices and differentials between light, medium and heavy oil prices; future oil and natural gas production levels; future exchange rates and interest rates; the amount of future cash distributions that we intend to pay; the cost of expanding our property holdings; our ability to obtain equipment in a timely manner to carry out development activities; our ability to market our oil and natural gas successfully to current and new customers; the impact of increasing competition; our ability to obtain financing on acceptable terms; and our ability to add production and reserves through our development and exploitation activities. In addition, many of the forward-looking statements contained in this document are located proximate to assumptions that are specific to those forward-looking statements, and such assumptions should be taken into account when reading such forward-looking statements.

Although Penn West believes that the expectations reflected in the forward-looking statements contained or incorporated by reference in this document, and the assumptions on which such forward-looking statements are made, are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking statements included or incorporated by reference in this document, as there can be no assurance that the plans, intentions or expectations upon which the forward-looking statements are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, which may cause Penn West's actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things: the impact of weather conditions on seasonal demand and our ability to execute capital programs; risks inherent in oil and natural gas operations; uncertainties associated with estimating reserves and resources; competition for, among other things, capital, acquisitions of reserves, resources, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions; geological, technical, drilling and processing problems; general economic conditions in Canada, the U.S. and globally, and in particular, the ongoing global financial crisis and its impacts on commodity prices and our access to capital; industry conditions, including fluctuations in the price of oil and natural gas;

royalties payable in respect of our oil and natural gas production and changes thereto; changes in government regulation of the oil and natural gas industry, including environmental regulation; fluctuations in foreign exchange or interest rates; unanticipated operating events that can reduce production or cause production to be shut-in or delayed; failure to obtain industry partner and other third-party consents and approvals when required; stock market volatility and market valuations; OPEC's ability to control production and balance global supply and demand of crude oil at desired price levels; political uncertainty, including the risks of hostilities, in the petroleum producing regions of the world; the need to obtain required approvals from regulatory authorities from time to time; failure to realize the anticipated benefits of acquisitions, including the completed and proposed acquisitions discussed herein; changes in taxation laws and regulations that affect us and our securityholders; changes in the Alberta royalty framework and their impact on us; uncertainty of obtaining required approvals in respect of acquisitions and mergers; and the other factors described under "Risk Factors" in this document and in Penn West's public filings available in Canada at www.sedar.com and in the United States at www.sec.gov. Readers are cautioned that this list of risk factors should not be construed as exhaustive.

The forward-looking statements contained and incorporated by reference in this document speak only as of the date of this document. Except as expressly required by applicable securities laws, Penn West does not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained and incorporated by reference in this document are expressly qualified by this cautionary statement.

NON-GAAP MEASURES

This Annual Information Form includes measures not defined under generally accepted accounting principles ("GAAP"), including funds flow and netback. Non-GAAP measures do not have any standardized meaning prescribed by GAAP and are therefore unlikely to be comparable to similar measures presented by other issuers. Funds flow is cash flow from operating activities before changes in non-cash working capital and asset retirement expenditures. Funds flow is used to assess our ability to fund distributions and planned capital programs. Netback is a per-unit-of-production measure of operating margin used in capital allocation decisions. For more information, see Penn West's management's discussion and analysis for the year ended December 31, 2008 (available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov), which includes a reconciliation of "funds flow" to cash flow from operating activities and sets out the method that we use to calculate our netbacks.

EFFECTIVE DATE OF INFORMATION

Except where otherwise indicated, the information in this Annual Information Form is presented as at the end of Penn West's most recently completed financial year, being December 31, 2008.

PENN WEST ENERGY TRUST

General

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

We commenced operations in our current structure on June 1, 2005 after the completion of a plan of arrangement under the ABCA. Pursuant to this plan of arrangement, holders of common shares of PWPL received three Trust Units for each one of their common shares.

Inter-Corporate Relationships

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

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

Our Organizational Structure

The following diagram sets forth the simplified organizational structure of Penn West.

Notes:

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

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

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

(4)	As at the date hereof, PWPL, Trocana Resources Inc. and Canetic Saskatchewan Trust are the partners of Penn West Partnership.

(5)

The other Operating Entities are direct or indirect wholly-owned subsidiaries of Penn West. As at December 31, 2008, other than PWPL and the Penn West Partnership, Penn West does not have any subsidiaries: (i) the total assets of which exceed 10% of Penn West's consolidated assets (or 20% of Penn West's consolidated assets when aggregated with all other subsidiaries of Penn West other than PWPL and the Penn West Partnership); or (ii) the sales and operating revenues of which exceed 10% of Penn West's consolidated sales and operating revenues (or 20% of Penn West's consolidated sales and operating revenues when aggregated with all other subsidiaries of Penn West other than PWPL and the Penn West Partnership).

GENERAL DEVELOPMENT OF THE BUSINESS

History and Development

Year Ended December 31, 2006

NYSE Listing

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

Petrofund Acquisition

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

Other Acquisitions and Dispositions

We completed property acquisitions, net of dispositions, of $6 million in 2006. Other than the Petrofund Acquisition described above, we did not complete any corporate acquisitions in 2006.

Changes to Taxation of Income Trusts

On October 31, 2006, the Federal Minister of Finance proposed to deny the deduction of distributions at the trust level and subject any income of certain publicly traded mutual fund trusts to tax at rates comparable to the combined federal and provincial corporate tax and to treat such distributions as taxable dividends to the unitholders (the "SIFT Tax"). On December 21, 2006, the Federal Minister of Finance released draft legislation to implement the SIFT Tax pursuant to which, commencing January 1, 2011 (provided we only experience "normal growth" and no "undue expansion" before then) certain distributions from us which would have otherwise been taxed as ordinary income generally will be characterized as dividends to our Unitholders and will be subject to tax at the corporate rates at the trust level. On June 22, 2007, the legislation received Royal assent.

The Trust is a taxable entity under the Tax Act and is taxable only on income that is not distributed or distributable to the Unitholders. As the Trust distributes all of its taxable income to the Unitholders pursuant to the Trust Indenture and currently satisfies the requirements of the Tax Act applicable to the Trust, the Trust does not expect to pay income taxes until the earlier of January 1, 2011 or if and when it ceases to be a trust. The SIFT Tax will not impose a tax on distributions from entities, such as the Trust, until January 1, 2011 as long as the Trust experiences only "normal growth" as set out in the guidelines described below. Commencing in January 2011, the Trust will be liable for tax on all distributions of income paid or payable to Unitholders, which distributions the Trust will no longer be able to deduct in computing its taxable income. The Trust currently has significant tax pools and expects to continue to increase its tax pool base until 2011. Accordingly, it is expected that the Trust will be able to shelter income for a period of time after the application of the SIFT Tax.

The SIFT Tax provides that, while there is no intention to prevent "normal growth" during the transitional period, any "undue expansion" would result in the transition period being terminated with the loss of the benefit to us of that transitional period. As a result, the adverse tax consequences resulting from the SIFT Tax could be borne sooner than January 1, 2011. On December 15, 2006, the Department of Finance issued guidelines with respect to what is meant by "normal growth" in this context. Specifically, the Department of Finance stated that "normal growth" would include equity growth within certain "safe harbour" limits, measured by reference to a specified investment flow-through's (a "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 and outstanding

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

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

Currently, the SIFT Tax rules provide that the SIFT Tax rate will be the federal general corporate income tax rate (which is anticipated to be 16.5% in 2011 and 15% in 2012) plus the provincial SIFT tax rate discussed below. Pursuant to proposed regulations to the Tax Act, the provincial SIFT Tax rate will be based on the general provincial corporate income tax rate in each province in which the Trust has a permanent establishment. For purposes of calculating this component of the tax, the general corporate taxable provincial allocation formula will be used. Specifically, the Trust's taxable distributions, if any, will be allocated to provinces by taking half of the aggregate of: (i) that proportion of the Trust's taxable distributions, if any, for the year that the Trust's wages and salaries in the province are of its total wages and salaries in Canada; and (ii) that proportion of the Trust's taxable distributions, if any, for the year that the Trust's gross revenues in the province are of its total gross revenues in Canada. It is anticipated that the Trust would be considered to have a permanent establishment in Alberta only, where the provincial tax rate in 2011 is expected to be 10%, which will result in an effective tax rate of 26.5% in 2011. Taxable distributions, if any, that are not allocated to any province, would instead be subject to a 10% rate constituting the provincial component.

On July 14, 2008, the Federal Minister of Finance announced proposed amendments to the Tax Act, including technical amendments to clarify certain aspects of the SIFT Tax and to provide rules to facilitate the conversion of existing SIFTs into corporations on a tax-deferred basis (the "Conversion Rules"). The Conversion Rules address many of the principal substantive and administrative issues that arise when structuring a corporate conversion of an income trust under the Tax Act. The Conversion Rules contemplate two alternatives for the conversion of a publicly-traded SIFT into a taxable Canadian corporation and the winding-up of the SIFT's underlying structure. The first alternative involves the winding-up of the SIFT into a taxable Canadian corporation whereas the second approach involves the distribution by the publicly-traded SIFT of shares of an underlying taxable Canadian corporation to its unitholders. The Conversion Rules will generally only apply to the winding-up of a SIFT or a distribution of shares completed after July 14, 2008 and before 2013. Bill C-10, which received Royal Assent on March 12, 2009, contained legislation implementing the Conversion Rules.

As a result of the enactment of the SIFT Tax in 2007, the future income taxes disclosed in our financial statements were adjusted to include temporary differences between the accounting and tax bases of our assets and liabilities at the trust level, as further described in Note 9 to our audited consolidated financial statements for the year ended December 31, 2008. In addition, the reported estimated net present value of future net revenues from our oil and natural gas reserves on an "after-tax" basis now reflects the impact of the SIFT Tax. We continue to evaluate alternatives to determine the optimal structure for our Unitholders beyond 2010. We are currently hesitant to make structural changes prior to the end of 2010 unless

opportunities arise, as we believe the exemption period has value for our Unitholders. Unless circumstances change within the current capital markets or the regulatory, tax or political environment, we currently believe that we will most likely convert into a dividend paying corporation. However, we are keeping our options open at this time and cannot provide any assurances in this regard. We do not expect that a conversion to a corporation would have a major impact on our underlying operating strategy or business affairs, but cannot provide any assurances in this regard. We expect that such a conversion could be achieved without creating a taxable event for most of our Unitholders, particularly if a conversion were completed prior to January 1, 2013. However, going forward, the tax treatment of our distributions or dividends might be different for our Unitholders or shareholders, as the case may be, depending on the Unitholder's tax jurisdiction and whether the Unitholder holds its investment in a taxable account or tax-deferred account. For additional information on the SIFT Tax, including its potential impact on us and our Unitholders and the actions that we might take in response to the SIFT Tax (including with respect to our anticipated tax horizon), see the following: "Risk Factors" in this Annual Information Form; "Other Oil and Gas Information – Tax Horizon" in Appendix A-3 to this Annual Information Form; and "Enactment of the Tax on Income Trusts" set forth in our management's discussion and analysis for the year ended December 31, 2008 (available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov), which disclosure is incorporated herein by reference.

Year Ended December 31, 2007

April 2007 Asset Acquisition

On April 11, 2007, Penn West completed the acquisition (the "April 2007 Asset Acquisition") of certain conventional oil and natural gas assets located primarily in the Province of Alberta, for cash consideration of approximately $329 million. As a result of the acquisition, Penn West acquired 6 MMbbl of light/medium crude oil and NGLs, 0.1 MMbbl of heavy oil and 16 Bcf of natural gas on a proved reserve basis, 8 MMbbl of light/medium crude oil and NGLs, 0.1 MMbbl of heavy oil and 22 Bcf of natural gas on a proved plus probable reserve basis, and 190,000 net acres of undeveloped land. The acquisition was financed using Penn West's existing syndicated credit facility and a new $250 million unsecured, demand credit facility.

Other Acquisitions and Dispositions

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

Private Placement of 2007 Senior Notes

Effective May 31, 2007, PWPL completed the private placement of an aggregate of US$475 million principal amount of notes (the "2007 Senior Notes"). The private placement consisted of the issuance of US$160 million principal amount of 5.68 percent notes due in 2015, US$155 million principal amount of 5.80 percent notes due in 2017, US$140 million principal amount of 5.90 percent notes due in 2019 and US$20 million principal amount of 6.05 percent notes due in 2022. The 2007 Senior Notes are unsecured and rank equally with Penn West's bank credit facilities. The proceeds of the 2007 Senior Notes were used to repay a portion of the indebtedness under Penn West's bank credit facilities.

Year Ended December 31, 2008

Vault Acquisition

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

In connection with the Vault Acquisition, Penn West also assumed approximately $89 million of bank indebtedness of Vault, $50 million principal amount of 7.2% Debentures issued by Vault and $49 million principal amount of 8% 2005 Debentures issued by Vault. On March 5, 2008, Penn West repurchased for cancellation $24 million principal amount of the 7.2% Debentures and $11,000 principal amount of the 8% 2005 Debentures pursuant to issuer bids required by the 7.2% Debenture Indenture and the 8% 2005 Debenture Indenture, respectively.

Canetic Acquisition

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

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

Concurrent with the closing of the Canetic Acquisition, Penn West secured a $4 billion credit facility for a three-year term with a syndicate of 18 Canadian and international banks. The new credit facility was initially used to retire Penn West's indebtedness under its then existing bank credit facilities and to retire all bank indebtedness assumed by Penn West in connection with the Vault Acquisition and the Canetic Acquisition.

Endev Acquisition

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

Other Acquisitions and Dispositions

We completed property dispositions, net of acquisitions, of $50 million in 2008.

Private Placement of 2008 Senior Notes

Effective May 29, 2008, PWPL completed the private placement of an aggregate of US$480 million and Cdn$30 million principal amount of senior guaranteed unsecured notes (the "2008 Senior Notes"). The private placement consisted of the issuance of US$153 million principal amount of 6.12 percent notes due in 2016, US$278 million principal amount of 6.30 percent notes due in 2018, Cdn$30 million principal amount of 6.16 percent notes due in 2018 and US$49 million principal amount of 6.40 percent notes due in 2020. The 2008 Senior Notes are unsecured and rank equally with PWPL's bank credit facilities and the 2007 Senior Notes. The proceeds of the private placement of the 2008 Senior Notes were used to repay a portion of the indebtedness outstanding under our bank credit facilities.

Private Placement of 2008 Pounds Sterling Senior Notes

Effective July 31, 2008, PWPL completed the private placement of an aggregate of £57 million principal amount of senior guaranteed unsecured notes (the "2008 Pounds Sterling Senior Notes"). The private placement consisted of the issuance of £57 million principal amount of 7.78 percent notes due in 2018. The 2008 Pounds Sterling Senior Notes are unsecured and rank equally with PWPL's bank credit facilities, the 2007 Senior Notes and the 2008 Senior Notes. The proceeds of the private placement of the 2008 Pounds Sterling Senior Notes were used to repay a portion of the indebtedness outstanding under our bank credit facilities.

Revisions to Alberta Royalty Regime

In December 2008, the Government of Alberta passed into law a "New Royalty Framework" which introduces new royalty rates for conventional oil, natural gas and bitumen effective January 1, 2009 that are sensitive to price and production levels and will apply to both new and existing oil sands projects and conventional oil and gas activities. Certain transitional rates and short-term incentives outside of the New Royalty Framework have also been provided by the Government of Alberta. In 2008, approximately 55% of our aggregate crude oil and natural gas production was from Alberta Crown leases. The net reserves volumes and estimated net present value of future net revenue attributable to our reserves located in Alberta contained in the reserves reported in Appendix A-3 to this Annual Information Form reflect Alberta's New Royalty Framework. For additional information, see the following: "Industry Conditions – Provincial Royalties and Incentives - Alberta" in this Annual Information Form; "Risk Factors" in this Annual Information Form; and "The New Alberta Royalty Framework" set forth in our management's discussion and analysis for the year ended December 31, 2008 (available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov), which disclosure is incorporated herein by reference.

Recent Developments

Public Offering of Trust Units

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

Acquisitions and Dispositions

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

Reece Acquisition

On March 10, 2009, Penn West announced its intention to add to its position in the Dodsland area of Saskatchewan with the acquisition of Reece Energy Exploration Corp. ("Reece") for a purchase price of approximately $92 million. Penn West will issue approximately 4.6 million Trust Units and assume approximately $40 million of debt in connection with the acquisition. The acquisition will add approximately 2,100 boe/d of production, of which approximately 67 percent is light oil, and approximately 75,000 net acres of undeveloped land, a significant portion of which is contiguous with our land position in the Dodsland area. The acquisition is currently scheduled to close on April 30, 2009, subject to the satisfaction of various industry standard closing conditions and the receipt of all necessary regulatory and other third party approvals, including the approval of Reece's shareholders and the Court of Queen's Bench of Alberta.

Significant Acquisitions

There were no significant acquisitions completed by Penn West during the financial year ended December 31, 2008 for which disclosure was required under Part 8 of National Instrument 51-102, other than the Canetic Acquisition. For a description of the Canetic Acquisition, see "General Development of the Business – History and Development – Year Ended December 31, 2008 - Canetic Acquisition" above. Penn West has filed a Form 51-102F4 – Business Acquisition Report in respect of the Canetic Acquisition.

DESCRIPTION OF OUR BUSINESS

Overview

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

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

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

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

PWPL

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

Internal Notes

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

NPIs

The Trust is a party to NPI Agreements with PWPL and certain other Operating Entities pursuant to which we have the right to receive the NPIs on petroleum and natural gas rights held by PWPL and the other Operating Entities from time to time. Pursuant to the terms of the agreements, we are entitled to a payment from PWPL and the other Operating Entities for each month equal to the amount by which 99 percent of the gross proceeds from the sale of production attributable to the property interests of PWPL and the other Operating Entities for such month exceeds 99 percent of certain deductible costs for such period. Deductible costs generally include capital expenditures, royalties, operating costs and certain interest expenses related to oil and gas activities. The term of the agreements is for as long as there are petroleum and natural gas rights to which the NPIs apply.

Reserves Data

See Appendices A-1, A-2 and A-3 for complete NI 51-101 oil and gas reserves disclosure for Penn West as at December 31, 2008.

CAPITALIZATION OF PWPL

Common Shares

PWPL has authorized for issuance an unlimited number of common shares. The Trust owns all of the issued common shares. The voting of such shares is delegated to the Board of Directors under the Trust Indenture other than: (i) any sale, lease or other disposition of, or any interest in, all or substantially all of the Trust's assets, except in conjunction with an internal reorganization of the Trust's direct or indirect assets as a result of which the Trust has the same, or substantially similar, interest, whether direct or indirect, in the assets as the interest, whether direct or indirect, that it had prior to the reorganization; (ii) any statutory amalgamation of PWPL with any other entity, except in conjunction with an internal reorganization as referred to in paragraph (i) above; (iii) any statutory arrangement involving PWPL, except in conjunction with an internal reorganization as referred to in paragraph (i) above; (iv) any amendment to the articles of PWPL to increase or decrease the minimum or maximum number of directors; or (v) any material amendment to the articles of PWPL to change the authorized share capital or amend the rights, privileges, restrictions and conditions attaching to any class of PWPL's shares in a manner which may be prejudicial to Penn West, without the approval of the Unitholders by special resolution at a meeting of Unitholders called for that purpose.

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

Preferred Shares

PWPL is authorized to issue an unlimited number of preferred shares in series. Before any shares of a particular series are issued, the Board of Directors shall, by resolution, fix the number of shares that will form such series and shall, subject to the limitations set out herein, by resolution fix the designation, rights, privileges, restrictions and conditions to be attached to the preferred shares of such series. The preferred shares of each series shall rank on a parity with the preferred shares of every other series with respect to accumulated dividends and return of capital. The preferred shares are entitled to a preference over the common shares and over any other shares of PWPL ranking junior to the preferred shares with respect to the payment of dividends and the distribution of assets in the event of the liquidation, dissolution or winding-up of PWPL, whether voluntary or involuntary, or any other distribution of the assets of PWPL among its shareholders for the purpose of winding-up its affairs.

The Board of Directors has authorized one series of preferred shares, being the first preferred shares series A (the "Series A Preferred Shares"). One thousand Series A Preferred Shares have been authorized for issuance. Holders of Series A Preferred Shares are entitled to receive preferential cash dividends in such amounts as may be declared by the Board of Directors. The payment of such dividends is in priority to dividends on the common shares of PWPL and all other shares ranking junior to the Series A Preferred Shares with respect to the payment of dividends. PWPL has the right to redeem at any time all, or from time to time any part, of the then outstanding Series A Preferred Shares at a price per share equal to $1,000, together with all accrued and unpaid dividends thereon up to the date fixed for redemption. Each registered holder of Series A Preferred Shares is entitled to require PWPL to retract at any time any Series A Preferred Shares tendered at a price per share equal to $1,000, together with all accrued and unpaid dividends thereon up to the retraction date. In the event of the liquidation, dissolution or winding-up of PWPL or other distribution of the assets of PWPL among its shareholders for the purpose of winding-up its affairs, the holders of Series A Preferred Shares are entitled to receive an amount per Series A Preferred Share equal to $1,000 per share, together with any accrued and unpaid dividends to the date of commencement of such event, to be paid all such money before any money shall be paid or property or assets distributed to the holders of any common shares of PWPL or other shares in the capital of PWPL ranking junior to the Series A Preferred Shares with respect to return of capital. After payment of the aforementioned amount, the Series A Preferred Shares shall not be entitled to share in any further distribution of the property or assets of PWPL. So long as any Series A Preferred Shares are outstanding PWPL may not, without the approval of the holders of the Series A Preferred Shares, take certain actions unless all dividends which have been declared have been paid or set apart for payment. Subject to applicable law, the holders of the Series A Preferred Shares are not entitled as such to any voting rights or to receive notice of or to attend any meeting of the

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

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

Borrowing

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

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

INFORMATION RELATING TO PENN WEST

Trust Units

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

As at March 26, 2009, approximately 408,249,304 million Trust Units were outstanding, approximately 6,020,546 million Trust Units were reserved for issuance on conversion of the Convertible Debentures and approximately 37,367,950 million Trust Units were available for future issuance pursuant to Penn West's trust unit rights incentive plan and employee stock savings plan (subject to increase in accordance with such plans).

Special Voting Units

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

Convertible Debentures

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

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

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

The 6.5% 2005 Debentures were originally issued in the aggregate principal amount of $60 million and approximately $18 million principal amount was outstanding at March 26, 2009. The 6.5% 2005 Debentures mature on July 31, 2010.

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

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

Terms of Convertible Debentures

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

The principal amount of the Convertible Debentures is payable in lawful money of Canada or, at the option of the Trust and subject to applicable regulatory approval, by payment of Trust Units as further described under "Payment Upon Redemption or Maturity" and "Redemption and Purchase". The interest on the Convertible Debentures is payable in lawful money of Canada and, in the case of certain of the Convertible Debentures, at the option of the Trust and subject to applicable regulatory approval, in accordance with the Interest Obligation as described under "Interest Payment Option".

The Convertible Debentures are direct obligations of the Trust and are not secured by any mortgage, pledge, hypothec or other charge and are subordinated to other liabilities of the Trust as described under "Subordination". The indentures governing the Convertible Debentures do not restrict the Trust from incurring additional indebtedness for borrowed money or from mortgaging, pledging or charging its properties to secure any indebtedness.

Conversion Privilege

The 8% 2004 Debentures are convertible at the holder's option into fully paid and non-assessable Trust Units at any time prior to the close of business on the earlier of August 31, 2009, and the last business day immediately preceding the date specified by Penn West for redemption of the 8% 2004 Debentures, at a conversion price of $30.2136 per Trust Unit, being a conversion rate of approximately 33.0977 Trust Units for each $1,000 principal amount of 8% 2004 Debentures.

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

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

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

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

Redemption and Purchase

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

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

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

The 6.5% 2006 Debentures are not redeemable on or before December 31, 2009. After December 31, 2009 and prior to maturity, the 6.5% 2006 Debentures may be redeemed in whole or in part from time to time at the option of the Trust on not more than 60 days and not less than 30 days prior notice, at a redemption price of $1,050 per 6.5% 2006 Debenture after December 31, 2009 and on or before December 31, 2010 and at a redemption price of $1,025 per 6.5% 2006 Debenture after December 31, 2010 and before maturity (each a "6.5% 2006 Redemption Price") in each case, plus accrued and unpaid interest thereon, if any.

The 7.2% Debentures are not redeemable on or before May 31, 2009. The Trust may, on not more than 60 days and not less than 30 days prior notice, redeem the 7.2% Debentures at a redemption price of $1,050 per 7.2% Debenture after May 31, 2009 and on or before May 31, 2010, and a price of $1,025 per 7.2% Debenture after May 31, 2010 and before May 31, 2011 (each a "7.2% Redemption Price"), plus accrued and unpaid interest thereon, if any.

The Trust has the right to purchase Convertible Debentures in the market, by tender or by private contract.

Payment upon Redemption or Maturity

On redemption or at maturity, the Trust will repay the indebtedness represented by the Convertible Debentures by paying to the Debenture Trustee in lawful money of Canada an amount equal to the aggregate applicable redemption price of the outstanding Convertible Debentures which are to be redeemed or the principal amount of the outstanding Convertible Debentures which have matured together with accrued and unpaid interest thereon up to but excluding the date of redemption or maturity, as applicable. The Trust may, at its option, and subject to applicable regulatory approval, elect to satisfy its obligation to pay the applicable redemption price of the Convertible Debentures which are to be redeemed or the principal amount of the Convertible Debentures which have matured, as the case may be, by issuing Trust Units to the holders of the Convertible Debentures. Any accrued and unpaid interest thereon will be paid in cash. The number of Trust Units to be issued will be determined by dividing the aggregate applicable redemption price of the outstanding Convertible Debentures which are to be redeemed or the principal amount of the outstanding Convertible Debentures which have matured, as the case may be, by 95 percent of the Current Market Price of the Trust Units on the date fixed for redemption or the maturity date, as the case may be. The term "Current Market Price" is defined in the Convertible Debenture indentures to mean the weighted average trading price of the Trust Units on the TSX for the 20 consecutive trading days ending on the fifth trading day preceding the date fixed for redemption or the maturity date, as the case may be.

Subordination

The payment of the principal of, and interest on, the Convertible Debentures is subordinated in right of payment, as set forth in the Debenture Indentures, to the prior payment in full of all Senior Indebtedness of the Trust. "Senior Indebtedness" of the Trust is defined in the Debenture Indentures as the principal of and premium, if any, and interest on and other amounts in respect of all indebtedness of the Trust (whether outstanding as at the date of the Debenture Indentures or thereafter incurred) which includes any indebtedness to trade creditors, other than indebtedness evidenced by the Convertible Debentures and all other existing and future debentures or other instruments of the Trust which, by the terms of the instrument creating or

evidencing the indebtedness, is expressed to be pari passu with, or subordinate in right of payment to, the Convertible Debentures.

The Debenture Indentures provide that in the event of any insolvency or bankruptcy proceedings, or any receivership, liquidation, reorganization or other similar proceedings relative to the Trust, or to its property or assets, or in the event of any proceedings for voluntary liquidation, dissolution or other winding-up of the Trust, whether or not involving insolvency or bankruptcy, or any marshalling of the assets and liabilities of the Trust, then those holders of Senior Indebtedness, including any indebtedness to trade creditors, will receive payment in full before the holders of Convertible Debentures will be entitled to receive any payment or distribution of any kind or character, whether in cash, property or securities, which may be payable or deliverable in any such event in respect of any of the Convertible Debentures or any unpaid interest accrued thereon. The Debenture Indentures also provide that the Trust will not make any payment, and the holders of the Convertible Debentures will not be entitled to demand, institute proceedings for the collection of, or receive any payment or benefit (including, without any limitation, by set-off, combination of accounts or realization of security or otherwise in any manner whatsoever) on account of indebtedness represented by the Convertible Debentures (a) in a manner inconsistent with the terms (as they exist on the date of issue) of the Convertible Debentures or (b) at any time when an event of default has occurred under the Senior Indebtedness and is continuing and the notice of such event of default has been given by or on behalf of the holders of Senior Indebtedness to the Trust, unless the Senior Indebtedness has been repaid in full.

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

Priority over Trust Distributions

The Debenture Indentures provide that certain expenses of the Trust must be deducted in calculating the amount to be distributed to the Unitholders. Accordingly, the funds required to satisfy the interest payable on the Convertible Debentures, as well as the amount payable upon redemption or maturity of the Convertible Debentures or upon an Event of Default (as defined below), will be deducted and withheld from the amounts that would otherwise be payable as distributions to Unitholders.

Change of Control of the Trust

Within 30 days following the occurrence of a change of control of the Trust involving the acquisition of voting control or direction over 66⅔ percent or more of the Trust Units (a "Change of Control"), the Trust is required to make an offer in writing to purchase all of the Convertible Debentures then outstanding (the "Debenture Offer"), at a price equal to 101 percent of the principal amount thereof plus accrued and unpaid interest (the "Debenture Offer Price").

If 90 percent or more of the aggregate principal amount of any series of Convertible Debentures outstanding on the date of the giving of notice of the Change of Control have been tendered to the Trust pursuant to the applicable Debenture Offer, the Trust will have the right and obligation to redeem all the remaining Convertible Debentures of that series, at the applicable Debenture Offer Price.

Interest Payment Option

The Trust may elect, from time to time, to satisfy its obligation to pay all or any part of the interest on the 6.5% 2006 Debentures, the 8% 2004 Debentures and the 6.5% 2005 Debentures (but, for greater certainty, not the 7.2% Debentures or the 8% 2005 Debentures) (the "Interest Obligation"), on the date it is payable under the applicable Debenture Indenture (an "Interest Payment Date"), by delivering sufficient Trust Units to the Debenture Trustee to satisfy all or the part, as the case may be, of the Interest Obligation in accordance with the applicable Debenture Indenture (the "Unit Interest Payment Election"). The Debenture Indentures provide that, upon such election, the Debenture Trustee shall: (a) accept delivery from the Trust of Trust Units; (b) accept bids with respect to, and consummate sales of, such Trust Units, each as the Trust shall direct in its absolute discretion; (c) invest the proceeds of such sales in short-term permitted government securities (as defined in the applicable Debenture Indenture) which mature prior to the applicable Interest Payment Date, and use the

proceeds received from such permitted government securities, together with any proceeds from the sale of Trust Units not invested as aforesaid, to satisfy the Interest Obligation; and (d) perform any other action necessarily incidental thereto.

If a Unit Interest Payment Election is made, the sole right of a holder of Convertible Debentures in respect of interest will be to receive cash from the Debenture Trustee out of the proceeds of the sale of Trust Units (plus any amount received by the Debenture Trustee from the Trust attributable to any fractional Trust Units) in full satisfaction of the Interest Obligation, and the holder of such Convertible Debentures will have no further recourse to the Trust in respect of the Interest Obligation.

Events of Default

The Debenture Indentures provide that an event of default ("Event of Default") in respect of the Convertible Debentures will occur if any one or more of the following described events has occurred and is continuing with respect of the Convertible Debentures: (a) failure for 10 days to pay interest on the Convertible Debentures when due; (b) failure to pay principal or premium, if any, on the Convertible Debentures when due, whether at maturity, upon redemption, by declaration or otherwise; (c) certain events of bankruptcy, insolvency or reorganization of the Trust under bankruptcy or insolvency laws; or (d) default in the observance or performance of any material covenant or condition of the Debenture Indentures and continuance of such default for a period of 30 days after notice in writing has been given by the Debenture Trustee to the Trust specifying such default and requiring the Trust to rectify the same. If an Event of Default has occurred and is continuing, the Debenture Trustee may, in its discretion, and shall upon request of holders of not less than 25 percent of the principal amount of the applicable Convertible Debentures then outstanding, declare the principal of and interest on all outstanding such Convertible Debentures to be immediately due and payable. In certain cases, the holders of more than 50 percent of the principal amount of the applicable Convertible Debentures then outstanding may, on behalf of the holders of all such Convertible Debentures, waive any Event of Default and/or cancel any such declaration upon such terms and conditions as such holders shall prescribe.

Offers for Debentures

The Debenture Indentures contain provisions to the effect that if an offer is made for any series of Convertible Debentures, which is a take-over bid for such series of Convertible Debentures within the meaning of the Securities Act (Alberta) and not less than 90 percent of such Convertible Debentures (other than Convertible Debentures held at the date of the take-over bid by or on behalf of the offeror or associates or affiliates of the offeror) are taken up and paid for by the offeror, the offeror will be entitled to acquire the Convertible Debentures held by the holders of such series of Convertible Debentures who did not accept the offer on the terms offered by the offeror.

Modification

The rights of the holders of the Convertible Debentures may be modified in accordance with the terms of the Debenture Indentures. For that purpose, among others, the Debenture Indentures contain certain provisions which will make binding on all Convertible Debenture holders' resolutions passed at meetings of the holders of Convertible Debentures by votes cast thereat by holders of not less than 66⅔ percent of the principal amount of the Convertible Debentures present at the meeting or represented by proxy, or rendered by instruments in writing signed by the holders of not less than 66⅔ percent of the principal amount of the Convertible Debentures then outstanding. In certain cases, the modification will, instead or in addition, require assent by the holders of the required percentage of Convertible Debentures of each particularly affected series.

Limitation on Issuance of Additional Convertible Debentures

The Debenture Indentures provide that the Trust shall not issue additional Convertible Debentures of equal ranking if the principal amount of all issued and outstanding Convertible Debenture of the Trust exceeds 25 percent of the Total Market Capitalization of the Trust immediately after the issuance of such additional Convertible Debenture. "Total Market Capitalization" is defined in the Debenture Indentures as the total principal amount of all issued and outstanding Convertible Debentures of the Trust which are convertible at the option of the holder into Trust Units plus the amount obtained by multiplying the number of issued and outstanding Trust Units by the Current Market Price of the Trust Units on the relevant date.

Limitation on Non-Resident Ownership

The Debenture Trustee may require declarations as to the jurisdictions in which beneficial owners of Convertible Debentures are resident. If the Debenture Trustee becomes aware as a result of requiring such declarations as to beneficial ownership, that the beneficial owners of 49 percent of the Trust Units then outstanding (40 percent in the case of the 6.5% 2006 Debentures and not more than half in the case of the 8% 2005 Debentures and the 7.2% Debentures), on a fully diluted basis, are, or may be, Non-Residents or that such a situation is imminent, the Debenture Trustee may make a public announcement thereof and shall not register a transfer of Convertible Debentures to a person unless the person provides a declaration that the person is not a Non-Resident. If, notwithstanding the foregoing, the Debenture Trustee determines that a majority of the Trust Units are held by Non-Residents, the Debenture Trustee may send a notice to Non-Resident holders of Convertible Debentures, chosen in inverse order to the order of acquisition or registration of the Convertible Debentures or in such manner as the Debenture Trustee may consider equitable and practicable, requiring them to sell their Convertible Debentures or a portion thereof within a specified period of not less than 60 days. If the Convertible Debenture holders receiving such notice have not sold the specified number of Convertible Debentures or provided the Debenture Trustee with satisfactory evidence that they are not Non-Residents within such period, the Debenture Trustee may, on behalf of such holder of Convertible Debentures, and in the interim shall, suspend the rights attached to such Convertible Debentures. Upon such sale the affected holders shall cease to be holders of Convertible Debentures, and their rights shall be limited to receiving the net proceeds of sale upon surrender of such Convertible Debentures.

Book-Entry System for Convertible Debentures

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

The 8% 2005 Debentures are issued as fully registered debentures in certificated form and beneficial holders of 8% 2005 Debentures may receive definitive certificates representing their interest in 8% 2005 Debentures.

Ratings

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

Trust Indenture

The Trust Indenture, among other things, provides for the calling of meetings of Unitholders, the conduct of business thereof, notice provisions, the appointment and removal of the Trustee and the form of Trust Unit certificates. The Trust Indenture may be amended from time to time. Substantive amendments to the Trust Indenture, including early termination of the Trust and the sale or transfer of our property as an entirety or substantially as an entirety, requires approval by special resolution of the Unitholders. See "Information Relating to the Trust – Meetings and Voting" below.

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

Trustee

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

good faith and in the Trust's best interests and in the best interest of the Unitholders and, in connection therewith, shall exercise that degree of care, diligence and skill that a reasonably prudent trustee would exercise in comparable circumstances.

In 2008, the Unitholders appointed the Trustee for an additional three-year term. The Unitholders are required to re-appoint or appoint a successor to the Trustee at the annual meeting of Unitholders three years following the re-appointment or appointment of the successor to the Trustee. The Trustee may also be removed by special resolution of the Unitholders. Such resignation or removal becomes effective upon the acceptance or appointment of a successor trustee.

PWPL presently administers the Trust on behalf of the Trustee. PWPL, on behalf of the Trustee, keeps such books and records as are necessary for the proper recording of the Trust's business transactions.

The Trust Indenture provides that the Trustee shall be under no liability for any action or failure to act unless such liabilities arise out of the Trustee's negligence, wilful default or fraud. The Trustee is indemnified out of the Trust's assets for any liabilities relating to any taxes or other government charges imposed upon the Trustee or in consequence of its performance of its duties unless such liabilities arise principally and directly out of gross negligence, wilful default or fraud of the Trustee, but has no additional recourse against Unitholders. In addition, the Trust Indenture contains other customary provisions limiting the liability of the Trustee.

The Trust Indenture also provides that the Trustee may without Unitholder approval amend the articles of PWPL to issue shares of PWPL which are exchangeable for Trust Units. There are no exchangeable shares issued or outstanding.

Future Offerings

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

Meetings and Voting

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

Unitholders will be entitled at each annual meeting to appoint the Trust's auditors and to elect all the members of the Board of Directors.

Our Management

The Board of Directors has generally been delegated all of the Trust's significant management decisions pursuant to the Trust Indenture and the Administration Agreement. For more information, see "Corporate Governance".

PWPL has accepted all such delegation and has agreed that, in respect of such matters, it shall carry out its functions honestly, in good faith and in the Trust's best interests and the best interests of the Unitholders and, in connection therewith, shall exercise that degree of care, diligence and skill that a reasonable person would exercise in comparable circumstances.

Limitation on Non-Resident Ownership

In order for the Trust to maintain its status as a mutual fund trust under the Tax Act, it must not be established or maintained primarily for the benefit of Non-Residents unless it satisfies the requirements of certain exceptions. The Trust Indenture provides that Penn West will use its best commercial efforts to maintain its status as a mutual fund trust under the Tax Act. Generally speaking, the Tax Act provides that a trust will permanently lose its "mutual fund trust" status (which is essential to the income trust structure) if it is established or maintained primarily for the benefit of Non-Residents (which is generally

interpreted to mean that the majority of unitholders must not be Non-Residents), unless at the relevant time, "all or substantially all" of the trust's property consists of property other than taxable Canadian property (the "TCP Exception"). We have determined that Penn West currently meets the requirement of the TCP Exception, and as a result, the Trust Indenture does not currently have a specific limit on the percentage of Trust Units that may be owned by Non-Residents.

Right of Redemption

Trust Units are redeemable at any time on demand by the holders thereof upon delivery to the Trust of the certificate or certificates representing such Trust Units, accompanied by a duly completed and properly executed notice requiring redemption. Upon receipt of the notice to redeem Trust Units by the Trust, the holder thereof shall only be entitled to receive a price per Trust Unit (the "Market Redemption Price") equal to the least of: (i) 95 percent of the "market price" of the Trust Units on the principal market on which the Trust Units are quoted for trading during the 10 trading day period commencing immediately after the date on which the Trust Units are tendered to the Trust for redemption; (ii) 95 percent of the closing market price on the principal market on which the Trust Units are quoted for trading on the date that the Trust Units are so tendered for redemption; and (iii) 95 percent of the closing market price of the Trust Units on the date of redemption.

For the purposes of this calculation, "market price" will be an amount equal to the simple average of the closing price of the Trust Units for each of the trading days on which there was a closing price; provided that, if the applicable exchange or market does not provide a closing price but only provides the highest and lowest prices of the Trust Units traded on a particular day, the market price shall be an amount equal to the simple average of the highest and lowest prices for each of the trading days on which there was a trade; and provided further that if there was trading on the applicable exchange or market for fewer than five of the 10 trading days, the market price shall be the simple average of the following prices established for each of the 10 trading days: the average of the 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 the exchange or market provides a closing price; and the average of the highest and lowest prices of the Trust Units for each day that there was trading, if the market provides only the highest and lowest prices of Trust Units traded on a particular day. The closing market price shall be: an amount equal to the closing price of the Trust Units if there was a trade on the date; an amount equal to the average of the highest and lowest prices of the Trust Units if there was trading and the exchange or other market provides only the highest and lowest prices of Trust Units traded on a particular day; and the average of the last bid and last ask prices if there was no trading on the date.

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

The redemption notes will be due on the third anniversary of the date of issuance and will bear interest at a rate per annum to be set by the Board of Directors in the context of the prevailing interest rates for debt instruments having equivalent terms and conditions. The redemption notes will be issued under a trust indenture and will provide for their issuance to the Trust in consideration of cash or as a reduction in the principal amount of the Internal Notes issued by PWPL to the Trust.

It is anticipated that this redemption right will not be the primary mechanism for holders of Trust Units to dispose of their Trust Units. Redemption notes which may be distributed in specie to Unitholders in connection with a redemption will not be listed on any stock exchange and no market is expected to develop in such redemption notes. Redemption notes may not be qualified investments for trusts governed by registered retirement savings plans, registered retirement income funds, deferred profit sharing plans, registered disability savings plans, registered education savings plans and tax free savings accounts.

Termination of the Trust

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

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

Reporting to Unitholders

Penn West's financial statements will be audited annually by an independent recognized firm of chartered accountants. Our audited financial statements, together with the report of such chartered accountants, will be mailed by the Trustee to Unitholders if previously requested and, if previously requested, the unaudited interim financial statements will be mailed to Unitholders within the periods prescribed by securities legislation. Penn West's year end is December 31. We are also subject to the continuous disclosure obligations under all applicable securities legislation.

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

CORPORATE GOVERNANCE

General

In general, PWPL has been delegated responsibility for substantially all of the management decisions of Penn West. The Unitholders are entitled to elect all of the members of the Board of Directors of PWPL pursuant to the terms of the Trust Indenture.

Trust Indenture

Pursuant to the Trust Indenture, Unitholders are entitled to direct the manner in which the Trust will vote its common shares in PWPL at all meetings in respect of matters relating to the election of the directors of PWPL, approving its financial statements and appointing auditors of PWPL who shall be the same as the Trust's auditors. Prior to the Trust voting its common shares in PWPL in respect of such matters, each Unitholder is entitled to vote in respect of the matter on the basis of one vote per Trust Unit held, and the Trust is required to vote its common shares in PWPL in accordance with the result of the vote of Unitholders.

Decision Making

The Board of Directors has a mandate to supervise the management of the Trust's business and affairs, PWPL and the Trust's other direct or indirect Subsidiaries and to act with a view to the Trust's best interest. The Board of Directors' mandate includes: (i) any offering of securities; (ii) ensuring compliance with all applicable laws, including in relation to an offering of securities; (iii) all matters relating to the content of any documents relating to an offering of securities, the accuracy of the disclosure contained therein, and the certification thereof; (iv) all matters concerning the terms of, and amendment from time to time of, material contracts; (v) all matters concerning any subscription agreement or underwriting or agency agreement providing for the sale or issue of Trust Units or securities convertible for or exchangeable into Trust Units or rights to acquire Trust Units; (vi) all matters relating to the redemption of Trust Units; (vii) all matters relating to the voting rights on any investments; (viii) all matters relating to the specific powers and authorities as set forth in the Trust Indenture; (ix) the adoption of a Unitholder rights plan and other miscellaneous matters relating to the maximization of Unitholder value; and (x) all matters relating to amending PWPL's articles to create exchangeable shares. The Board of Directors holds regularly

scheduled meetings at least quarterly to review the business and affairs of the Trust's Subsidiaries and make any necessary decisions relating thereto.

The Trust Indenture gives to the Board of Directors the authority to exercise the rights, powers and privileges for all matters relating to the maximization of Unitholder value in the context of a take-over bid (an "Offer") including any Unitholder rights protection plan, any defensive action to an Offer, any directors circular in response to an Offer, any regulatory or court proceeding relating to an Offer and any related or ancillary matter.

Distributions and Distribution Policy

Cash distributions are made 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 last business day of each such calendar month or such other date as determined from time to time by the Trustee.

The Board of Directors (on behalf of the Trust) reviews the distribution policy from time to time. Distributions are not guaranteed and the amount that we distribute per Trust Unit on a monthly basis may be reduced from time to time, or even eliminated. The actual amount distributed will be dependent on various factors, including the commodity price environment, the amount of capital expenditures that we make, our production levels and numerous other economic and operational factors, many of which are beyond our control. The amount of distributions that we make (if any) is at the discretion of the Board of Directors of PWPL. See "Risk Factors". The current distribution policy targets the use of approximately 60 percent to 70 percent of funds flow for distribution to Unitholders. Depending upon various factors, including commodity prices and the size of Penn West's capital budget, it is expected that approximately 30 percent to 40 percent of funds flow will fund all or a portion of Penn West's annual capital expenditure program, including exploration, exploitation expenditures and minor property acquisitions, but excluding major acquisitions.

Distributions are normally announced on a monthly basis in the context of prevailing and anticipated commodity prices. During periods of volatile commodity prices, we may vary the distribution rate monthly. On January 14, 2009, we announced that in light of our intended 2009 capital expenditure levels and the continuing weak commodity price environment, the Board of Directors had approved a reduction to our monthly distribution to Unitholders from $0.34 per Trust Unit per month to $0.23 per Trust Unit per month for the next two months (subject to changes in commodity prices, production levels and capital expenditures), commencing with the distribution paid on February 13, 2009 to Unitholders of record on January 30, 2009. On March 26, 2009, we subsequently announced that in light of our revised 2009 capital expenditure levels and the continuing weak commodity price environment, the Board of Directors had approved a further reduction to our monthly distribution to Unitholders from $0.23 per Trust Unit per month to $0.15 per Trust Unit per month, subject to changes in commodity prices, production levels and capital expenditures, commencing with the distribution to be paid on May 15, 2009 to Unitholders of record on April 30, 2009.

Pursuant to the provisions of the Trust Indenture all taxable income earned by Penn West in a fiscal year, not previously distributed in that fiscal year, must be distributed to Unitholders of record on December 31 of such year. This excess income, if any, will be allocated to 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 trade with the Trust Units until determined and declared payable in accordance with the rules of the TSX. To the extent that a Unitholder trades Trust Units in this period they will be allocated such income but will dispose of their right to receive the cash or Trust Units comprising such a distribution.

The credit agreement governing PWPL's syndicated credit facility and the note purchase agreements governing PWPL's 2007 Senior Notes, 2008 Senior Notes and 2008 Pounds Sterling Senior Notes each contain provisions which restrict the ability of the Trust to pay distributions to Unitholders in the event of the occurrence of certain events of default. For further information regarding the credit agreement governing our syndicated credit facility, reference is made to Note 6 (Long-Term Debt) of our consolidated financial statements for the year ended December 31, 2008. For further information regarding the note purchase agreements governing PWPL's 2007 Senior Notes, 2008 Senior Notes and 2008 Pounds Sterling Senior Notes, reference is made to note 6 (Long-Term Debt) of our consolidated financial statements for the year ended December 31, 2008. Note 6 (Long-Term Debt) of our consolidated financial statements for the year ended December 31, 2008 is incorporated by reference in this Annual Information Form. Our consolidated financial statements for the year ended December 31, 2008 are filed on SEDAR at www.sedar.com.

Directors and Executive Officers of PWPL

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

Name, Province/State and Country of Residence	Positions and Offices Held	Principal Occupations during the Five Preceding Years
James E. Allard(1)(5)(6) Alberta, Canada	Director since June 30, 2006	Independent director and business advisor. Also, a member of the Alberta Securities Commission from 1999 to 2005.
William E. Andrew Alberta, Canada	Chief Executive Officer Director since June 3, 1994	Chief Executive Officer of PWPL since January 11, 2008. Prior thereto, President and Chief Executive Officer of PWPL since May 2005. Prior thereto, President of PWPL.
Robert G. Brawn(3)(5) Alberta, Canada	Director since January 11, 2008	President of 738831 Alberta Ltd. (a private investment company) since 2003. Prior thereto, Chairman of Acclaim Energy Inc. ("Acclaim"), the administrator of Acclaim Energy Trust (a public oil and gas income trust), a predecessor of Canetic.
George H. Brookman(2)(4) Alberta, Canada	Director since August 3, 2005	President and Chief Executive Officer of West Canadian Industries Group Inc. (a commercial digital printing and graphics company).
John A. Brussa Alberta, Canada	Chairman of the Board of Directors Director since April 21, 1995	Senior Partner, Burnet, Duckworth & Palmer LLP (barristers and solicitors).
Daryl Gilbert(2)(3)(5) Alberta, Canada	Director since January 11, 2008	Independent business consultant since 2005 and a corporate director of a number of companies. President and Chief Executive Officer of GLJ Petroleum Consultants Ltd. (formerly Gilbert Laustsen Jung Associates Ltd.) (an engineering consulting firm) until 2005.
Shirley A. McClellan(1)(4)(5) Alberta, Canada	Director since June 8, 2007	Distinguished Scholar in Residence at the University of Alberta for the Faculties of Agriculture and Rural Economy and the School of Business. Independent businesswoman since 2007. Prior thereto, Deputy Premier of the Province of Alberta from 2001 to 2007 and Minister of Finance of the Province of Alberta from 2004 to 2007.
Frank Potter(1)(4)(6) Ontario, Canada	Director since June 30, 2006	Chairman of Emerging Markets Advisors, Inc. (an investment consulting firm).
R. Gregory Rich(2)(4) Texas, United States	Director since January 11, 2008	Principal of Blackrock Energy Associates (an energy consulting and investment firm), since October 2002.

Name, Province/State and Country of Residence

Positions and Offices Held

Principal Occupations

during the Five Preceding Years

Jack Schanck(3)(5) Texas, United States	Director since June 2, 2008	Managing Partner of Tecton Energy, LLC since 2007, a Texas-based oil and natural gas exploration and production company. Prior thereto, Chief Executive Officer of SouthView Energy LLC, an oil and natural gas investment company, from 2005 to 2007. Prior thereto, Co-Chief Executive Officer of Samson Investment Company.
James C. Smith(1)(2)(3) Alberta, Canada	Director since May 31, 2005	Independent director and consultant to a number of public and private oil and gas companies.
Murray Nunns Alberta, Canada	President and Chief Operating Officer	President and Chief Operating Officer of PWPL since February 8, 2008. Prior thereto, director of PWPL and Executive Chairman of Monterey Exploration Ltd., a private oil and gas company. Prior thereto, a variety of management positions at Rio Alto Exploration Ltd., a public oil and gas company.
Todd H. Takeyasu Alberta, Canada	Executive Vice President and Chief Financial Officer	Executive Vice President and Chief Financial Officer of PWPL since February 8, 2008. Prior thereto, Senior Vice President, Finance – Treasury of PWPL since January 11, 2008. Prior thereto, Senior Vice President and Chief Financial Officer of PWPL since 2006. Prior thereto, Vice President, Finance of PWPL since 2005. Prior thereto, Treasurer of PWPL.
David W. Middleton Alberta, Canada	Executive Vice President, Engineering and Corporate Development	Executive Vice President, Engineering and Corporate Development of PWPL since November 3, 2008. Prior thereto, Executive Vice President, Operations and Corporate Development of PWPL since February 8, 2008. Prior thereto, Chief Operating Officer of PWPL since January 11, 2008. Prior thereto, Executive Vice President and Chief Operating Officer of PWPL since 2005. Prior thereto, Senior Vice President, Production of PWPL since 2003.
Mark P. Fitzgerald Alberta, Canada	Senior Vice President, Production	Senior Vice President, Production of PWPL since November 3, 2008. Prior thereto, Senior Vice President, Engineering of PWPL since January 11, 2008. Prior thereto, Vice President, Operations of Canetic since January 2006. Prior thereto, Vice President, Operations of Acclaim since February 2005. Prior thereto, Vice President, Engineering of Acclaim (since 2004) and Manager, Western District of Acclaim (from 2003 to 2004).
Thane A.E. Jensen Alberta, Canada	Senior Vice President, Operations Engineering	Senior Vice President, Operations Engineering of PWPL since November 3, 2008. Prior thereto, Senior Vice President, Exploration and Development of PWPL since 2005. Prior thereto, Vice President, Engineering of PWPL since 2004.

Name, Province/State and Country of Residence

Positions and Offices Held

Principal Occupations

during the Five Preceding Years

Keith Luft Alberta, Canada		General Counsel and Senior Vice President, Stakeholder Relations		General Counsel and Senior Vice President, Stakeholder Relations of PWPL since February 8, 2008. Prior thereto, Senior Vice President, Stakeholder Relations of PWPL since January 11, 2008. Prior thereto, Vice President, Land and Legal of PWPL since 2006. Prior thereto, Senior Solicitor of Conoco Phillips Canada Ltd. / Burlington Resources Canada Ltd. (an oil and gas company) since May 2004.
Hilary Foulkes Alberta, Canada		Senior Vice-President, Business Development		Senior Vice-President, Business Development of PWPL since April 29, 2008. Prior thereto, a Managing Director with the investment banking firm, Scotia Waterous for 8 years. Prior thereto, various positions as a geologist in exploration and development roles with Gulf Canada Resources.

Notes:

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

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

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

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

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

(6)	Member of the Acquisitions and Divestments Committee of the Board of Directors.

As at March 26, 2009, the directors and executive officers of PWPL, as a group, beneficially owned, or controlled or directed, directly or indirectly, approximately one million Trust Units or less than one percent of the issued and outstanding Trust Units.

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

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

(a)

was subject to a cease trade order (including a management cease trade order), an order similar to a cease trade order or an order that denied the relevant company access to any exemption under securities legislation, in each case that was in effect for a period of more than 30 consecutive days (collectively, an "Order") that was issued while the director or executive officer was acting in the capacity as director, Chief Executive Officer or Chief Financial Officer; or

(b)

was subject to an Order that was issued after the director or executive officer ceased to be a director, Chief Executive Officer or Chief Financial Officer and which resulted from an event that occurred while that person was acting in the capacity as director, Chief Executive Officer or Chief Financial Officer.

Daryl Gilbert is a director of Globel Direct, Inc., which was subject to a cease trade order issued by the British Columbia Securities Commission on November 20, 2002 and the Alberta Securities Commission on November 22, 2002 for delay in filing financial statements. The required financial statements were filed and the cease trade orders were revoked effective December 23, 2002. The company sought and received protection under CCAA in June 2007, and after a failed restructuring effort, a receiver was appointed by one of the company's lenders in December 2007. The company has since ceased operations and is delisted.

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

(a)

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

(b)

has, within the ten years before the date of this Annual Information Form, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the director, executive officer or shareholder.

John A. Brussa was a director of Imperial Metals Limited, a corporation engaged in both oil and gas and mining operations, in the year prior to that corporation implementing a plan of arrangement under the Company Act (British Columbia) and under the Companies' Creditors Arrangement Act (Canada) which resulted in the separation of its two businesses. The reorganization resulted in the creation of two public corporations, Imperial Metals Corporation and IEI Energy Inc. (subsequently renamed Rider Resources Ltd.), both of which were listed on the TSX.

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

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

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

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

Conflicts of Interest

The Board of Directors has adopted a Code of Business Conduct and Ethics and a Code of Ethics for Officers and Senior Financial Management (the "Codes"). In general, the private investment activities of employees, directors and officers are not prohibited; however, should an existing investment pose a potential conflict of interest, the potential conflict is required by the Codes to be disclosed to the President, Chief Executive Officer or the Board of Directors. Any other activities posing a potential conflict of interest are also required by the Codes to be disclosed to the Chief Executive Officer or the Board of Directors. Any such potential conflicts of interests will be dealt with openly with full disclosure of the nature and extent of the potential conflicts of interests with Penn West.

It is acknowledged in the Codes that the directors may be directors or officers of other entities engaged in the oil and gas business, and that such entities may compete directly or indirectly with Penn West. Passive investments in public or private entities of less than one per cent of the outstanding shares will not be viewed as "competing" with Penn West. No executive officer or employee of PWPL should be a director or officer of any entity engaged in the oil and gas business unless expressly authorized by the Board of Directors. Any director of PWPL who is actively engaged in the management of, or who owns an investment of one per cent or more of the outstanding shares, in public or private entities shall disclose such holding to the Board of Directors. In the event that any circumstance should arise as a result of such positions or investments being held or otherwise which in the opinion of the Board of Directors constitutes a conflict of interest which reasonably affects such person's ability to act with a view to the best interests of Penn West, the Board of Directors will take such actions

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

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

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

Promoters

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

AUDIT COMMITTEE DISCLOSURES

National Instrument 52-110 ("NI 52-110") relating to audit committees has mandated certain disclosures for inclusion in this Annual Information Form. The text of the Audit Committee's mandate is attached as Appendix "B" to this Annual Information Form.

Composition of the Audit Committee and Relevant Education and Experience

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

James C. Smith (Chairman)

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

James E. Allard

Mr. Allard is an independent director and business advisor. He has a Bachelor of Science degree in Business Administration from the University of Connecticut and completed the Advanced Management Program at Harvard University. Mr. Allard has focused his career on international finance in the petroleum industry for the past 40 years, during which time he has served as the Chief Executive Officer, Chief Financial Officer and/or a director of a number of publicly traded and private companies. Over the past nine years he has served on the board of the Alberta Securities Commission, acted as the sole external trustee and advisor to a mid-sized pension plan and served as a director and advisor to several companies. From 1981 to 1995, Mr. Allard served as a senior executive officer of Amoco Corporation and as a director of Amoco Canada, which at that time was Canada's largest natural gas producer.

Frank Potter

Mr. Potter has a background in international banking in Europe, the Middle East and the United States. He managed the international business of one of Canada's principal banks before being appointed Executive Director of the World Bank in Washington where he served for nine years. Mr. Potter subsequently served as a Senior Advisor at the Department of Finance for the Canadian government. He is currently the Chairman of Emerging Markets Advisors, Inc., a Toronto based consultancy that assists corporations in making and managing direct investments internationally. Mr. Potter serves on a number of boards, including Canadian Tire Corporation, Limited, the Royal Ontario Museum and Softchoice Corporation.

Shirley A. McClellan

Mrs. McClellan is a Distinguished Scholar in Residence at the University of Alberta for the Faculties of Agriculture and Rural Economy and the School of Business. She lectures primarily in Rural Economy and the School of Business. Mrs. McClellan brings to Penn West the experience gained over 20 years of distinguished service to the Province of Alberta. Her career included the offices of Deputy Premier of Alberta from 2001 to 2007, Minister of Finance of Alberta from 2004 to 2007 and Chair of the Treasury Board and Vice-Chair of the Agenda and Priorities Committee of the Government of Alberta. Mrs. McClellan served a total of six terms as a Member of the Alberta Legislative Assembly representing the constituency of Drumheller-Stettler. Over this time period, she held numerous other portfolios, including Minister of Agriculture, Food and Rural Development, Minister of International and Intergovernmental Relations, Minister of Community Development, and Minister of Health.

Pre-Approval Policies and Procedures for Non-Audit Services

The terms of the engagement of Penn West's external auditors to provide audit services, including the budgeted fees for such audit services and the representations and disclaimer relating thereto, must be pre-approved by the entire Audit Committee.

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

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

External Auditor Service Fees

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

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

Notes:

(1)	The aggregate fees billed by our external auditor in each of the last two fiscal years for audit services, including Sarbanes – Oxley compliance related services.

(2)

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

(3)

The aggregate fees billed in each of the last two fiscal years by our external auditor for professional services for tax compliance, tax advice and tax planning. The services comprising the fees disclosed under this category principally consisted of assistance and advice in relation to the communication of the taxability of distributions to Unitholders.

(4)	The aggregate fees billed in each of the last two fiscal years by our external auditor for products and services not included under the headings "Audit Fees", "Audit Related Fees" and "Tax Fees".

Reliance on Exemptions

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

Audit Committee Oversight

At no time since the commencement of Penn West's most recently completed financial year has a recommendation of the Audit Committee to nominate or compensate an external auditor not been adopted by the Board of Directors of PWPL.

DISTRIBUTIONS TO UNITHOLDERS

During the three most recently completed financial years, we have declared the following amount of cash distributions per Trust Unit, each amount being paid in the following month:

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

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

MARKET FOR SECURITIES

Units

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

	TSX
	Unit price ($)		Unit price ($)
Period	High		Low		Volume

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

	NYSE
	Unit price (US$)		Unit price (US$)
Period	High		Low		Volume

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

Convertible Debentures Assumed Pursuant to the Vault Acquisition

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

7.2% 2006 Debentures

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

	TSX
	Debenture price ($)		Debenture price ($)
Period	High		Low		Volume

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

8% 2005 Debentures

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

	TSX
	Debenture price ($)		Debenture price ($)
Period	High		Low		Volume

January (15-31)		-		-		-
February		-		-		-
March		104.50		104.50		300
April		-		-		-
May		-		-		-
June		106.55		104.00		1,480
July		-		-		-
August		105.99		105.99		100
September		105.00		104.03		5,490
October		104.25		104.25		100
November		-		-		-
December		100.00		100.00		330

Convertible Debentures Assumed Pursuant to the Canetic Acquisition

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

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

6.5% 2005 Debentures

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

	TSX
	Debenture price ($)		Debenture price ($)
Period	High		Low		Volume

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

6.5% 2006 Debentures

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

	TSX
	Debenture price ($)		Debenture price ($)
Period	High		Low		Volume

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

8% 2004 Debentures

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

	TSX
	Debenture price ($)		Debenture price ($)
Period	High		Low		Volume

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

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

INDUSTRY CONDITIONS

The oil and natural gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration, development, production, refining, transportation, and marketing) imposed by legislation enacted by various levels of government and with respect to pricing and taxation of oil and natural gas by agreements among the governments of Canada, Alberta, British Columbia, and Saskatchewan, all of which should be carefully considered by investors in the oil and gas industry. It is not expected that any of these controls or regulations will affect our operations in a manner materially different 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 to predict what additional legislation or amendments may be enacted. Outlined below are some of the principal aspects of legislation, regulations and agreements governing the oil and gas industry.

Pricing and Marketing - Oil and Natural Gas

The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. Oil prices are primarily based on worldwide supply and demand. The specific price depends in part on oil quality, prices of competing fuels, distance to market, the value of refined products, the supply/demand balance, and other contractual terms. Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order approving such export has been obtained from the National Energy Board of Canada (the "NEB"). Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the NEB and the issuance of such licence requires a public hearing and the approval of the Governor in Council.

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

The governments of Alberta, British Columbia, and Saskatchewan also regulate the volume of natural gas that may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements, and market considerations.

Pipeline Capacity

Although pipeline expansions are ongoing, the lack of firm pipeline capacity continues to affect the oil and natural gas industry from time to time by limiting the ability to produce and to market oil and natural gas production. In addition, the pro-rationing of capacity on the inter-provincial pipeline systems from time to time also continues to affect the ability to export oil and natural gas.

The North American Free Trade Agreement

The North American Free Trade Agreement ("NAFTA") among the governments of Canada, United States of America, and Mexico became effective on January 1, 1994. NAFTA carries forward most of the material energy terms that are contained in the Canada United States Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports of energy resources to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to domestic use (based upon the proportion prevailing in the most recent 36 month period); (ii) impose an export price higher than the domestic price subject to an exception with respect to certain voluntary measures which only restrict the volume of exports; and (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum or maximum export or import price requirements, provided, in the case of export price requirements, any prohibition in any circumstances in which any other form of quantitative restriction is prohibited, and in the case of import-price requirements, such requirements do not apply with respect to enforcement of countervailing and anti-dumping orders and undertakings.

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

Provincial Royalties and Incentives

General

In addition to federal regulation, each province has legislation and regulations that govern land tenure, royalties, production rates, environmental protection, and other matters. The royalty regime is a significant factor in the profitability of crude oil, natural gas liquids, sulphur, and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiation between the mineral freehold owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery, and the type or quality of the petroleum product produced. Other royalties and royalty-like interests are, from time to time, carved out of the working interest owner's interest through non-public transactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests, or net carried interests.

Occasionally the governments of the western Canadian provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays, and tax credits, and are generally introduced when commodity prices are low. The programs are designed to encourage exploration and development activity by improving earnings and cash flow within the industry. Royalty holidays and reductions would reduce the amount of Crown royalties paid by oil and gas producers to the provincial governments and would increase the net income and funds from operations of such producers. However, the trend in recent years, in light of high commodity prices, has been for provincial governments to eliminate, amend or allow such incentive programs to expire without renewal. Recent actions taken by provincial governments (and in particular the Alberta government) in response to the quick and significant decrease in commodity prices signal that this trend has slowed and may be changing course (at least temporarily until commodity prices recover). See below for further details.

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

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

Alberta

In Alberta, companies are granted the right to explore, produce and develop petroleum and natural gas resources in exchange for royalties, bonus bid payments and rents. On October 25, 2007, the Government of Alberta released a report entitled "The New Royalty Framework" (the "NRF") containing the Government's proposals for Alberta's new royalty regime, which was followed by the Mines and Minerals (New Royalty Framework) Amendment Act, 2008, which was given Royal Assent on December 2, 2008. The NRF and the applicable new legislation became effective on January 1, 2009. Prior to the NRF, the amount of royalties that were payable was influenced by the oil production, density of the oil, and the vintage of the oil. Originally, the vintage classified oil was "new oil" and "old oil" depending on when the oil pools were discovered. If the pool was discovered prior to March 31, 1974 it was considered "old oil", if it was discovered after March 31, 1974 and before September 1, 1992, it was considered "new oil". The Alberta Government introduced in 1992 a Third Tier Royalty with a base rate of 10% and a rate cap of 25% for oil pools discovered after September 1, 1992. The new oil royalty reserved to the Crown had a base rate of 10% and a rate cap of 30%. The old oil royalty reserved to the Crown had a base rate of 10% and a rate cap of 35%. The NRF eliminates this classification and establishes new royalty rates for conventional oil, natural gas and oil sands. The new royalty rates for conventional oil are set by a single sliding rate formula which is applied monthly and increases the old royalty from 30% to 35% applied to the old and new tiers, to up to 50% and with rate caps once the price of conventional oil reaches $120 per barrel. The sliding rate formula includes in its calculation the price of oil and well production.

With respect to natural gas, and similar to the conventional oil framework, the royalties outlined in the NRF are set by a single sliding rate formula ranging from 5% to 50% with a rate cap once the price of natural gas reaches $16.59/GJ. Prior to the NRF, the royalty reserved to the Crown in respect of natural gas production, subject to various incentives, was between 15% and 30%, in the case of new natural gas, and between 15% and 35%, in the case of old natural gas, depending upon a prescribed or corporate average reference price. In response to the drop in commodity prices experienced during the second half of 2008, the Government of Alberta announced on November 19, 2008, the introduction of a five year program of transitional royalty rates with the intent of promoting new drilling. Under this new program companies drilling new natural gas or conventional oil deep wells (between 1,000 and 3,500 metres) will be given a one-time option, on a well by well basis, to adopt either the new transitional royalty rates or those outlined in the NRF. In order to qualify for this program wells must be drilled during the period starting on November 19, 2008 and ending on December 31, 2013. Following this period all new wells drilled will automatically be subject to the NRF.

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

On April 10, 2008, the Government of Alberta introduced two new royalty programs that will encourage the development of deep oil and gas reserves: (a) a five-year oil program for exploration wells over 2,000 metres that will provide royalty adjustments to offset higher drilling costs and provide a greater incentive for producers to continue to pursue new, deeper oil plays (these oil wells will qualify for up to a $1 million or 12 months of royalty offsets, whichever comes first); and (b) a five-year natural gas deep drilling program that will replace the existing program in order to encourage continued deep gas exploration for wells deeper than 2,500 metres (the program will create a sliding scale of royalty credit according to depth, of up to $3,750 per metre). These new programs are being implemented along with the NRF.

Regulations made pursuant to the Mines and Minerals Act (Alberta) provided various incentives for exploring and developing oil reserves in Alberta. However, the Alberta Government announced in August of 2006 that four royalty programs were to be amended, a new program was to be introduced and the Alberta Royalty Tax Credit Program was to be eliminated, effective January 1, 2007. The programs affected by this announcement were: (i) Deep Gas Royalty Holiday; (ii) Low Productivity Well Royalty Reduction; (iii) Reactivated Well Royalty Exemption; and (iv) Horizontal Re-Entry Royalty Reduction. The program introduced was the Innovative Energy Technologies Program (the "IETP"), which has a stated

objective of promoting the producers' investment in research, technology and innovation for the purposes of improving environmental performance while creating commercial value. The IETP provides royalty reductions that are presumed to reduce financial risk. Alberta Energy decides which projects qualify and the level of support that will be provided. The deadline for the IETP's final round of applications was September 20, 2008. The successful applicants for the first two rounds have been announced, and those for the third round selection are scheduled to be announced in the first half of 2009. The technical information gathered from this program is to be made public once a two-year confidentiality period expires.

The NRF includes a policy of "shallow rights reversion". The Government of Alberta started to implement this policy on January 1, 2009, and its intent is to maximize the development of currently undeveloped resources that is consistent with the Government of Alberta's objective of maximizing recovery of known gas resources, while increasing royalty revenues. The policy's stated objective is for the mineral rights to shallow gas geological formations that are not being developed to revert back to the Government and be made available for resale, and in the event of non-productive shallow wells, to sever the rights from shallow zones and encourage increased production from up-hole zones. The shallow rights reversion policy affects all petroleum and natural gas agreements; however, the timing of the reversion will differ depending on whether the leases and licenses were acquired prior to January 1, 2009 or subsequent to January 1, 2009. Leases granted after January 1, 2009 will be subject to shallow rights reversion at the expiry of the primary term, and in the event of a licence the policy will apply at the expiry of the intermediate term. Holders of leases or licences that have been continued indefinitely prior to January 1, 2009 will receive a notice regarding the reversion of the shallow rights, which will be implemented three years from the date of the notice. The lease or licence holder can make a request to extend this period. The order in which these agreements will receive the reversion notice will depend on the vintage of their term, with the older leases and licenses receiving a reversion notice first. Leases or licences that were granted prior to January 1, 2009 but have not yet been continued will have a grace period until they are continued under section 15 of the P&G Tenure Regulation and will be subject to deeper rights reversion prior to receiving a shallow rights reversion notice.

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

The three-point incentive program also includes an investment of $30 million by the Government of Alberta in abandonment and reclamation projects for orphan wells. The stated objective of this investment is to encourage the cleanup of inactive oil and gas wells and to stimulate new activity within the services sector.

British Columbia

Producers of oil and natural gas in British Columbia are required to pay annual rental payments with respect to the Crown leases and royalties and freehold production taxes in respect of oil and gas produced from Crown and freehold lands. The amount payable as a royalty in respect of oil depends on the type of oil, the value of the oil, the quantity of oil produced in a month, and the vintage of the oil. Generally, the vintage of oil is based on the determination of whether the oil is produced from a pool discovered before October 31, 1975 (old oil), between October 31, 1975 and June 1, 1998 (new oil), or after June 1, 1998 (third-tier oil). The royalty rates are calculated in three stages, which take into account the vintage of the oil, if the oil produced has already been sold and any royalty exempt value applicable (exempt wells). Oil produced from newly discovered pools may be exempt from the payment of a royalty for the first 36 months of production or 11,450m3 produced, whichever comes first; and the royalties for third-tier oil are the lowest reflecting the higher costs of exploration and extraction that the producers incur. The royalty payable on 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 prescribed minimum price. However, when the reference price is below the select price (a parameter used in the royalty rate formula), the royalty rate is fixed. As an incentive for the production and marketing of natural gas, which may have been flared, natural gas produced in association with oil has a lower royalty than the royalty payable on non-conservation gas.

On May 30, 2003, the Ministry of Energy and Mines for British Columbia announced an Oil and Gas Development Strategy for the Heartlands ("Strategy"). The Strategy is a comprehensive program to address road infrastructure, targeted royalties and regulatory reduction, and British Columbia service sector opportunities. In addition, the Strategy is intended to result in economic and employment opportunities for communities in British Columbia's heartlands.

Some of the financial incentives in the Strategy include:

Royalty credits towards the construction, upgrading, and maintenance of road infrastructure in support of resource exploration and development. Funding will be contingent upon an equal contribution from industry. This program has evolved over past years as a result of the Province's stated objective to increase competitiveness. On March 2, 2009, the Government of British Columbia announced the 2009 Infrastructure Royalty Credit Program ("Program"), which allocates $120 million in royalty credits for oil and gas companies. The Program provides access to royalty credits to oil and gas companies with respect to certain approved road construction or pipeline infrastructure projects intended to improve, or make possible, the access to new and underdeveloped oil and gas areas. Companies must apply to the Ministry of Energy and Mines for British Columbia prior to 2:00 p.m. on April 30, 2009 to be considered for approval under the program.

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

The British Columbia Energy Plan announced on February 27, 2007 outlines the requirements for the development of goals for conservation, energy efficiency and clean energy. In addition, its stated goals include to promote competitiveness through the implementation of a Net Profit Royalty Program ("NPRP") and facilitate the development of the oil and gas industry. The NPRP's objective is to share the capital risk of successful developments. Pursuant to the Net Profit Royalty Regulation, the holder of a lease can apply to pay monthly net profit royalties on production of oil and for natural gas wells within a proposed project. The amount paid is calculated on the producer's interest in the project, and it ranges from 2% to 5% of the gross revenue and 15% to 35% of the net revenues received. In addition, it depends on which stage the well is at, which may be either pre-payout, after-payout or already producing marketable gas.

The Government of British Columbia has introduced a few more royalty programs, in addition to the ones previously mentioned, including a royalty program for deep discovery wells, royalty programs with a stated goal of attracting investment to less productive shallow gas wells (Ultra-Marginal Royalty Program), and the implementation of royalty credits to assist the development of the coal-bed gas reserves found in the Province of British Columbia.

Saskatchewan

In Saskatchewan, the amount payable as a royalty in respect of oil depends on the vintage of the oil, the type of oil, the quantity of oil produced in a month, and the value of the oil. For Crown royalty and freehold production tax purposes, crude oil is considered "heavy oil", "southwest designated oil", or "non-heavy oil other than southwest designated oil". The conventional royalty and production tax classifications of oil production are applicable to each of the three crude oil types. The Crown royalty and freehold production tax structure for crude oil is price sensitive and varies between the base royalty rates of 5% for all "fourth tier oil" to 20% for "old oil". Marginal royalty rates are 30% for all "fourth tier oil" to 45% for "old oil".

The amount payable as a royalty in respect of natural gas is determined by a sliding scale based on a reference price (which is the greater of the amount obtained by the producer and a prescribed minimum price), the quantity produced in a given month, the type of natural gas, and the vintage of the natural gas. As an incentive for the production and marketing of natural gas which may have been flared, the royalty rate on natural gas produced in association with oil is less than on non-associated natural gas. The royalty and production tax classifications of gas production are "fourth tier gas" introduced October 1, 2002, "third tier gas", "new gas", and "old gas". The Crown royalty and freehold production tax for gas is price sensitive and varies between the base royalty rate of 5% for "fourth tier gas" and 20% for "old gas". The marginal royalty rates are between 30% for "fourth tier gas" and 45% for "old gas".

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

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

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

·	The elimination of the re-entry and short section horizontal oil well royalty/tax categories. All horizontal oil wells with a finished drilling date on or after October 1, 2002 will receive the "fourth tier" royalty/ tax rates and new incentive volumes.

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

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

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

On June 19, 2007, the Government of Saskatchewan introduced the Orphan Well and Facility Liability Management Program pursuant to the amendment of the Oil and Gas Conservation Act and the Oil and Gas Conservation Regulations, 1985. The program includes a security deposit, which has two purposes: (i) preventing any person with insufficient financial capability from acquiring oil and gas wells or facilities; and (ii) in the case of a bankrupt company, the funds cover the decommissioning and reclaiming of orphan properties. An additional change introduced is the mandatory licensing of all upstream oil and gas facilities in Saskatchewan.

Land Tenure

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

Environmental Regulation

The oil and natural gas industry is subject to environmental regulations pursuant to a variety of provincial and federal legislation. Such legislation provides for restrictions and prohibitions on the release or emission of various substances produced in association with certain oil and gas industry operations. In addition, such legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage, and the imposition of material fines and penalties.

Alberta

Environmental legislation in Alberta has been consolidated into the Environmental Protection and Enhancement Act (Alberta) (the "EPEA"), which came into force on September 1, 1993, and the Oil and Gas Conservation Act (Alberta) (the "OGCA"). The EPEA and OGCA impose stricter environmental standards, require more stringent compliance, reporting and monitoring obligations, and significantly increased penalties. In 2006, the Alberta Government enacted regulations pursuant to the EPEA to specifically target sulphur oxide and nitrous oxide emissions from industrial operations including the oil and gas industry. In addition, the reduction emission guidelines outlined in the Climate Change and Emissions Management Amendment Act came into effect on July 1, 2007 ("CCEMAA"). Under this legislation, Alberta facilities emitting more than 100,000 tonnes of greenhouse gases a year must reduce their emissions intensity by 12%. Industries have three options to choose from in order to meet the reduction requirements outlined in this legislation: (i) by making improvements to operations that result in reductions; (ii) by purchasing emission credits from other sectors or facilities that have emissions below the 100,000 tonne threshold and are voluntarily reducing their emission; or (iii) by contributing to the Climate Change and Emissions Management Fund (the "Fund"). Industries can either choose one of these options or a combination thereof. Pursuant to CCEMAA and the Specified Gas Emitters Regulation, companies were obliged to reduce their emission intensity by 12% by March 31, 2008. Alberta industries have achieved 2.6 million tonnes of actual reduction, due to changes in operations and investing on verified offset projects. In addition, certain companies contributed $40 million to the Fund. It is reasonably likely that the trend towards stricter standards in environmental legislation and regulation will continue.

On January 24, 2008, the Alberta Government announced a new climate change action plan that will cut Alberta's projected 400 million tonnes of emissions in half by 2050. This plan focuses on three areas: (i) carbon capture and storage, which will be mandatory for in situ oil sand facilities that use heavy fuels for steam generation; (ii) energy conservation and efficiency; and (iii) greening production through increased investment in clean energy technology, including supporting research on new oil sands extraction processes and funding projects that reduce the cost of separating carbon dioxide from other emissions. In addition to this action plan, the Provincial Energy Strategy unveiled on December 11, 2008 is expected to, among other things, support the upgrading, refining and petrochemical clusters existing in the Province, market Alberta's energy internationally, review the emission targets and carbon charges applied to large facilities, and promote the innovation of energy technology by encouraging investment in research and development.

British Columbia

British Columbia's Environmental Assessment Act became effective on June 30, 1995. This legislation rolls the previous processes for the review of major energy projects into a single environmental assessment process with public participation in the environmental review process. On February 27, 2007, the Government of British Columbia unveiled the Energy Plan outlining its strategy towards the environment, which includes targeting zero net greenhouse gas emissions, promoting new investments in innovation, and becoming the world's leader in sustainable environmental management. For this purpose, on December 18, 2007 proposals were sought for applications to the Innovative Clean Energy Fund, in order to attract new technologies that will help solve energy and environmental issues. With regards to the oil and natural gas industry the objective is to achieve clean energy through conservation and energy efficient practices, while competitiveness is advocated in order to attract investment for the development of the oil and natural gas sector. Among the changes to be implemented are: (i) a new Net Profit Royalty Program; (ii) the creation of a Petroleum Registry; (iii) the establishment of an infrastructure royalty program (combining roads and pipelines); (iv) the elimination of routine flaring at producing wells; (v) the creation of policies and measures for the reduction of emissions; (vi) the development of unconventional resources such as tight gas and coalbed gas; and (vii) the new Oil and Gas Technology Transfer Incentive Program that encourages the research, development and use of innovative technologies to increase recoveries from existing reserves and promotes responsible development of new oil and gas reserves. In furtherance of these initiatives, on July 1, 2008 the Government of British Columbia introduced revenue-neutral carbon tax legislation that is applied to all fossil fuels used in the Province of British Columbia. The tax would be phased in, and the initial rate would be based on CO2 equivalent of $10 per tonne for the first six months of 2009 and $15 per tonne for the last six months of 2009, followed by $5 per tonne increases in July of every year until 2012. Tax credits and reductions will be used in order to offset the tax revenues that the Government of British Columbia would receive otherwise. On April 3, 2008, the Government of British Columbia introduced the Greenhouse Gas Reduction (Cap and Trade) Act, which will allow participation in the Western Climate Initiative cap and trade system that is currently being developed. The system establishes a limit on emissions and allows regulated emitters to buy/sell emission allowances or offset emits. The emitter is obliged to obtain emission allowances (compliance units) equal to the amount of

greenhouse gases emitted within a certain period of time, and that are supposed to be surrendered to the Government of British Columbia as proof of compliance.

Federal

In December 2002, the Government of Canada ratified the Kyoto Protocol ("Kyoto Protocol"). The Kyoto Protocol calls for Canada to reduce its greenhouse gas emissions to 6% below 1990 "business-as-usual" levels between 2008 and 2012. Given revised estimates of Canada's normal emissions levels, this target translates into an approximately 40% gross reduction in Canada's current emissions. It is uncertain, based on the Updated Action Plan announced by the Federal Government (see below), that the Kyoto Protocol target of 6% below 1990 emission levels will be enforced in Canada. Bill C-288, which is intended to ensure that Canada meets its global climate change obligations under the Kyoto Protocol, was passed by the House of Commons on February 14, 2007. On April 26, 2007, the Federal Government released its Action Plan to Reduce Greenhouse Gases and Air Pollution (the "Action Plan") (also known as ecoACTION), which includes the regulatory framework for air emissions. This Action Plan covers not only large industry, but regulates the fuel efficiency of vehicles and the strengthening of energy standards for a number of energy using products.

On January 31, 2008, the Government of Canada and the Province of Alberta released the final report of the Canada-Alberta ecoENERGY Carbon Capture and Storage Task Force, which recommends, among others things: (i) incorporating carbon capture and storage into Canada's clean air regulations; (ii) allocating new funding into projects through competitive process; and (iii) targeting research to lower the cost of technology.

In order to strengthen the Action Plan, on March 10, 2008, the Government of Canada released "Turning the Corner – Taking Action to Fight Climate Change" (the "Updated Action Plan"), which provides some additional guidance with respect to the Government's plan to reduce greenhouse gas emissions by 20% by 2020 and by 60% to 70% by 2050.

The Updated Action Plan is primarily directed towards industrial emissions from certain specified industries, including the oil sands, oil and gas and refining. The Updated Action Plan is intended to create a carbon emissions trading market, including an offset system, to provide an incentive to reduce greenhouse gas emissions and establish a market price for carbon. There are mandatory reductions of 18% from the 2006 baseline starting in 2010 and an additional 2% in subsequent years for existing facilities. This target will be applied to regulated sectors on a facility-specific, sector-wide or corporate basis. In the case of oil sands production, petroleum refining, natural gas pipelines and upstream oil and gas the target will be considered facility-specific (sectors in which the facilities are complex and diverse, or where emissions are affected by factors beyond the control of the facility operator). Emissions from new facilities, which are those built between 2004 and 2011, will be based on a cleaner fuel standard to encourage continuous emissions intensity reductions over time, and will be granted a 3-year grace period during which no emissions intensity targets will apply. Targets will begin to apply on the fourth year of commercial operation and the baseline will be the third year's emissions intensity, with a 2% continuous annual emission intensity improvement required. The definition of new facility also includes greenfield facilities, major expansions constituting more than a 25% increase in a facility's physical capacity, as well as transformations to a facility that involve significant changes to its processes. For upstream oil and gas and natural gas pipelines, it will be applied using a sector-specific approach. For the oil sands, its application will be process-specific: oil sands plants built in 2012 and later, those which use heavier hydrocarbons, up-graders and in-situ production will have mandatory standards in 2018 that will be based on carbon capture and storage.

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

Four separate compliance mechanisms are provided in respect of the above targets: Technology Fund contributions, offset credits, clean development credits and credits for early action. The most significant of these compliance mechanisms, at least initially, will be the Technology Fund, to which regulated entities will be able to contribute in order to comply with emissions intensity reductions. The contribution rate will increase over time, beginning at $15 per tonne for the 2010 to 2012 period, rising to $20 per tonne in 2013, and thereafter increasing at the nominal rate of gross domestic product growth. Contribution limits will correspondingly decline from 70% in 2010 to 0% in 2018. Monies raised through contributions to the Technology Fund will be used to invest in technology to reduce greenhouse gas emissions. Alternatively, regulated entities may be able

to receive credits for investing in large-scale and transformative projects at the same contribution rate and under similar requirements as mentioned above.

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

Under the Updated Action Plan, regulated entities will also be able to purchase credits created through the Clean Development Mechanism of the Kyoto Protocol. The purchase of such emissions reduction credits will be restricted to 10% of each firm's regulatory obligation, with the added restriction that credits generated through forest sink projects will not be available for use in complying with the Canadian regulations.

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

Penn West and the Environment

We understand our responsibilities of reducing the environmental impacts from our operations and 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 our operations, and to involving stakeholders throughout the exploration, development, production and abandonment process. Our environmental programs encompass resource conservation, stakeholder communication and site abandonment/reclamation. Our environmental programs are monitored to ensure that they comply with all government environmental regulations and with our own environmental policies. The results of these programs are reviewed with our management and operations personnel.

Our Environmental Policy and Environmental Management Plan ("EMP") encompass the full range of air, water, soil and waste issues associated with exploration, development and production. The EMP includes guidelines to 11 key areas that are considered in conjunction with oil and natural gas development plans. These guidelines help ensure safe and environmentally sound field operations. The Environmental Operating Guidelines are used to train our employees in the practical and economic implementation of the EMP.

We maintain a program of detailed inspections, audits and field assessments to determine and quantify the environmental liabilities that will be incurred during the eventual decommissioning and reclamation of our field facilities. We pursue a program of environmental impact reduction aimed at minimizing these future corporate liabilities without hampering field productivity. This program, launched in 1994 and ongoing into 2009, includes measures to remediate potential contaminant sources, reclaim spill sites and abandon unproductive wells and shut-in facilities. We have implemented strategies to reduce greenhouse gas emissions and flaring and continued the program to test CO2 enhanced oil recovery methods, which would "sequester" CO2 in hydrocarbon reservoirs.

Alberta and British Columbia are currently the only jurisdictions, in which we operate, that have passed legislation regarding greenhouse gas emissions. We do not operate any facilities in Alberta that are regulated to reduce green house gas (GHG) emissions. However, we do have minor working interests in five non-operated facilities that were required to meet the Alberta regulations. All of our fuel use in British Columbia is subject to a carbon tax based on consumption. The financial obligation, in both Alberta and British Columbia, is not material at this time.

Because the federal and provincial programs relating to the regulation of the emission of greenhouse gases and other air pollutants continue to be developed, we are currently unable to predict the total impact of the potential regulations upon our business. Therefore, it is possible that we could face increases in operating costs in order to comply with emissions legislation. However, in cooperation with the Canadian Association of Petroleum Producers, we will continue to work cooperatively with governments to develop an approach to deal with climate change issues that protects the industry's competitiveness, limits the cost and administrative burden of compliance and supports continued investment in the sector. In the meantime, we will continue our current activities to reduce our emissions intensity, improve energy efficiency and develop CO2 injection and sequestration infrastructure.

Penn West provides additional information on greenhouse gases on our website and also participates in the annual international Carbon Disclosure Project. These two sources detail significantly more information regarding emissions, business strategy, governance, and potential risks for those who are interested.

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

We are committed to meeting our responsibilities to protect the environment wherever we operate and we anticipate making increased expenditures of both a capital and an expense nature as a result of the increasingly stringent laws relating to the protection of the environment. We will be taking such steps as required to ensure continued compliance with applicable environmental legislation in each jurisdiction in which we operate. We believe that we are currently in material compliance with applicable environmental laws and regulations. We also believe that it is reasonably likely that the trend towards stricter standards in environmental legislation and regulation will continue.

RISK FACTORS

The following is a summary of certain risk factors relating to the business of Penn West and the Operating Entities. The following information is a summary only of certain risk factors and is qualified in its entirety by reference to, and must be read in conjunction with, the detailed information appearing elsewhere in this Annual Information Form. Unitholders and potential Unitholders should consider carefully the information contained herein and, in particular, the following risk factors. If any of these risks occur, our production, revenues and financial condition could be materially harmed, with a resulting decrease in distributions on, and the market price of, our Trust Units.

Volatility in oil and natural gas prices could have a material adverse effect on our results of operations and financial condition, which in turn could negatively affect the amount of distributions paid to our Unitholders.

Our results of operations and financial condition are dependent upon the prices that we receive for the oil and natural gas that we sell. Historically, the oil and natural gas markets have been volatile and are likely to continue to be volatile in the future. Oil and natural gas prices have fluctuated widely during recent years and are subject to fluctuations in response to relatively minor changes in supply, demand, market uncertainty and other factors that are beyond our control. These factors include, but are not limited to:

·	global energy policy, including the ability of OPEC to set and maintain production levels and influence prices for oil;

·	political instability and hostilities and the risk of hostilities;

·	foreign supply of oil and natural gas, including liquefied natural gas;

·	weather conditions;

·	the overall level of energy demand;

·	production and storage levels of natural gas;

·	government regulations and taxes;

·	currency exchange rates;

·	the availability of transportation infrastructure;

·	the effect of worldwide environmental and/or energy conservation measures;

·	the price and availability of alternative energy supplies; and

·	the overall economic environment.

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

The price of oil and natural gas is affected by political events throughout the world. Any such event could result in a material decline in prices and result in a reduction of the funds flow available for distribution to Unitholders.

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

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

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

Recent market events and conditions, including disruptions in the international credit markets and other financial systems and the deterioration of global economic conditions, have caused significant volatility to commodity prices. These conditions worsened in 2008 and are continuing in 2009, causing a loss of confidence in the broader U.S. and global credit and financial markets and resulting in the collapse of, and government intervention in, major banks, financial institutions and insurers and creating a climate of greater volatility, less liquidity, widening of credit spreads, a lack of price transparency, increased credit losses and tighter credit conditions. Notwithstanding various actions taken by governments, concerns about the general condition of the capital markets, financial instruments, banks, investment banks, insurers and other financial institutions caused the broader credit markets to further deteriorate and stock markets to decline substantially. These factors have negatively impacted company valuations and are expected to impact the performance of the global economy going forward.

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

As a result of the weakened global economic situation, we (and all other oil and gas entities) expect to have restricted access to capital and increased borrowing costs for the foreseeable future. Although our business and asset base have not changed materially, the lending capacity of all financial institutions has diminished and risk premiums have increased. As future capital expenditures will be financed out of cash generated from operations, borrowings and possible future equity sales, our ability to do so is dependent on, among other factors, the overall state of capital markets and investor appetite for investments in the energy industry and our securities in particular.

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

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

We may not be able to repay all or part of our indebtedness, or alternatively refinance all or part of our indebtedness on commercially reasonable terms. We may not be able to comply with the covenants (and in particular the financial covenants) contained in our debt instruments. The occurrence of any one of these events could have a material adverse effect on our results of operations and financial condition, which in turn could negatively affect the amount of distributions paid to our Unitholders.

We currently have credit facilities in place that have an aggregate borrowing limit of $4.0 billion and a maturity date of January 11, 2011. As of December 31, 2008, approximately $2.6 billion was outstanding under our credit facilities. The credit facilities are comprised of two tranches which each revolve until their respective maturity dates. Tranche one of our credit facilities has an aggregate borrowing limit of $3.25 billion and is extendible with lender approval. We have the right to request an extension of the maturity date under tranche one such that the term to maturity does not exceed three years. Tranche two of our credit facilities has an aggregate borrowing limit of $750 million and is non-extendible. In the event that tranche one of our credit facilities is not extended before January 11, 2011, all outstanding indebtedness under our credit facilities will be repayable at that date. There is also a risk that our credit facilities will not be renewed for the same principal amount or on the same terms. Any of these events could adversely affect our ability to fund our ongoing operations and, as repayment of such indebtedness has priority over the payment of cash distributions to Unitholders, to distribute cash to Unitholders.

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

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

We may be unable to successfully compete with other companies in our industry, which could negatively affect the market price of our Trust Units and distributions to our Unitholders.

There is strong competition relating to all aspects of the oil and gas industry. We compete with numerous other trusts and conventional exploration and production companies for, among other things:

capital;

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

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

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

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

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

time to time, we may issue Trust Units from treasury in order to reduce debt and maintain a more optimal capital structure. Conversely, to the extent that external sources of capital, including the issuance of additional Trust Units, becomes limited or unavailable, our ability to make the necessary capital investments to maintain or expand our oil and gas reserves will be impaired. We believe that the SIFT Tax imposed by the Government of Canada will substantially eliminate the competitive advantage that we and other energy trusts have enjoyed relative to our industry competitors in raising capital in a tax-efficient manner. To the extent that we are required to use additional funds flow to finance capital expenditures or property acquisitions or to pay debt service charges or to reduce debt, the amount of funds flow available for distribution to Unitholders will be reduced.

Our hedging program could result in us not realizing the full benefit of oil and natural gas price increases.

We may manage the risk associated with changes in commodity prices by entering into oil or natural gas price hedges. If we hedge our commodity price exposure, we could forego the benefits we would otherwise experience if commodity prices increase. In addition, commodity hedging activities could expose us to cash and income losses. To the extent that we engage in risk management activities, there are credit risks associated with counterparties with which we contract.

Being a limited purpose trust makes us largely dependent upon the operations and assets of the Operating Entities. If the oil and natural gas reserves associated with the Operating Entities' resource properties are not supplemented through additional development activities or the acquisition of oil and natural gas properties, the ability of the Operating Entities to continue to generate funds flow from operations for distribution to Unitholders may become adversely affected.

We are entirely dependent upon the operations and assets of the Operating Entities through our ownership, directly and indirectly, of securities of the Operating Entities, including the common shares of PWPL, the Internal Notes and the NPIs. Accordingly, our ability to pay cash distributions to Unitholders are dependent upon the ability of the Operating Entities to meet their interest, principal, dividend and other distribution obligations on the securities of the Operating Entities and the NPIs. The Operating Entities' income is received from the production of oil and natural gas from the Operating Entities' resource properties and is susceptible to the risks and uncertainties associated with the oil and natural gas industry generally.

If we are unable to acquire additional reserves, the value of our Trust Units and distributions to Unitholders will decline.

Distributions of income from our properties, absent commodity price increases or cost effective exploration, acquisition and development activities, will decline over time in a manner consistent with declining production from typical oil, natural gas and natural gas liquids reserves. As we distribute a portion of our funds flow to Unitholders, we do not reinvest funds flow in the same manner as some non-trust industry participants and we only conduct limited exploratory activities. Accordingly, absent equity capital injections or increased debt levels, our production levels and reserves will decline over time and, absent changes to other factors such as increases in commodity prices, the level of income available for distributions will also decline over time.

Our future oil and natural gas reserves and production, and therefore our funds flow, will be highly dependent on our success in exploring and exploiting our reserves and land base and acquiring additional reserves. Without reserve additions through acquisition, exploration or development activities, our reserves and production will decline over time as our existing reserves are depleted.

To the extent that external sources of capital, including the issuance of additional Trust Units, become limited or unavailable, our ability to make the necessary capital investments to maintain or expand our oil and natural gas reserves may be impaired. To the extent that we are required to use higher proportions of funds flow to finance capital expenditures or property acquisitions, the level of funds flow available for distributions will be reduced.

There can be no assurance that we will be successful in developing or acquiring additional reserves on terms that meet our investment objectives.

Fluctuations in foreign currency exchange rates and interest rates could adversely affect our business, and adversely affect the market price of our Trust Units and distributions to our Unitholders.

World oil prices are based on United States dollars and the Canadian dollar price received by Canadian producers is therefore affected by the Canadian/U.S. dollar exchange rate, which fluctuates over time. In recent years, the Canadian dollar has increased materially in value against the United States dollar and has at times traded above par against the United States dollar (although the Canadian dollar has recently declined sharply against the United States dollar). Any such material increases in the value of the Canadian dollar negatively affect our production revenues. Any future strengthening of the Canadian dollar against the United States dollar could negatively affect the funds available for future distributions and the future value of our reserves as determined by independent evaluators.

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

Actual reserves will vary from reserves estimates and those variations could be material, and negatively affect the market price of our Trust Units and distributions to our Unitholders.

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

·	historical production from the properties;

·	production rates;

·	ultimate reserve recovery;

·	timing and amount of capital expenditures;

·	marketability of oil and natural gas;

·	royalty rates;

·	the assumed effects of regulation by governmental agencies; and

·	future operating costs;

all of which may vary from actual results. As a result, estimates of the economically recoverable oil and natural gas reserves or estimates of resources attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom prepared by different engineers, or by the same engineers at different times, may vary. Our actual production, revenues and development and operating expenditures will vary from reserve and resource estimates thereof and such variations could be material.

Estimates of proved reserves that may be developed and produced in the future are sometimes based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history and production practices will result in variations in the estimated reserves and such variations could be material.

In accordance with applicable securities laws, GLJ and Sproule have used forecast price and cost estimates in calculating reserve quantities included herein. Actual future net funds flows will be affected by other factors including but not limited to actual production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs.

Actual production and funds flows derived from reserves will vary from the reserve estimates contained in the engineering reports summarized herein, and such variations could be material. The engineering reports summarized herein are based in part on the assumption that certain activities will be undertaken by us in future years and the further assumption that such activities will be successful. The reserves and estimated funds flows to be derived therefrom contained in the engineering reports summarized herein will be reduced, in future years, to the extent that such activities are not undertaken or, if undertaken, do not achieve the level of success assumed in the engineering reports summarized herein.

Our operation of oil and natural gas wells, and our participation in oil and natural gas wells operated by others, could subject us to environmental claims and liability and/or increased compliance costs, all of which could affect the market price of our Trust Units and reduce distributions to Unitholders.

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and natural gas operations. The legislation also requires that wells, pipelines and associated facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and legal liability, and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require our Operating Entities to incur costs to remedy such discharge. Furthermore, we believe the political climate appears to favour new programs for environmental laws and regulation, particularly in relation to the reduction of emissions. Any such programs, laws or regulations, if proposed and enacted, may contain emission reduction targets that we cannot meet, and financial penalties or charges could be incurred as a result of the failure to meet such targets.

In particular, there is uncertainty regarding the Kyoto Protocol, the federal government's Clean Air Act of 2006, the federal government's Action Plan to Reduce Greenhouse Gases and Air Pollution announced on April 26, 2007 (the "Action Plan") and the federal government's update to the Action Plan announced on March 10, 2008 (the "Updated Action Plan"). The Clean Air Act proposes to reduce greenhouse gas emissions and other contaminants; however, emission targets and compliance deadlines differ from those outlined in the Kyoto Protocol which was ratified by Canada. The Action Plan (also known as ecoACTION) includes the regulatory framework for air emissions. The Updated Action Plan provides additional guidance with respect to the federal government plan to reduce greenhouse gas emissions by 20% by 2020 and by 60% to 70% by 2050. The Updated Action Plan is primarily directed towards industrial emissions from certain specified industries including the oil sands, oil and gas and refining industries. If passed, the Clean Air Act, the Action Plan and the Updated Action Plan may have adverse operational and financial implications to us. Provincial emission reduction requirements, such as those contained in Alberta's Climate Change and Emissions Management Act, in addition to the plan announced by the Alberta government on January 24, 2008, may require the reduction of emissions or emissions intensity of our operations and facilities. The direct or indirect costs of these regulations may adversely and materially affect our business. No assurance can be given that environmental laws will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise adversely affect our financial condition, results of operations or prospects. Future changes in other environmental legislation could occur and result in stricter standards of enforcement, larger fines and liability, and increased capital expenditures and operating costs, which could have a material adverse effect on our financial condition or results of operations. See "Industry Conditions – Environmental Regulation" herein.

Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not currently possible to predict either the nature of those requirements or the impact on us and our operations and financial condition.

We depend upon our management and other key personnel and the loss of one or more of such individuals could negatively affect our business.

Unitholders depend upon the management of PWPL in respect of the administration and management of all matters relating to our operations. The success of our operations depends largely upon the skills and expertise of our senior management and other key personnel. Our continued success depends upon our ability to retain and recruit such personnel. Investors who are not willing to rely on the management of PWPL should not invest in our securities.

Our strategy in the current economic and industry environment may subject us to certain risks.

In light of the current economic and commodity price environment, we have reduced our planned 2009 capital expenditures and our monthly distribution to Unitholders significantly from 2008 levels, in each case in an effort to minimize further increases in debt levels and position ourselves to capitalize on acquisition opportunities. There are certain risks associated with this strategy, including that: (i) reduced capital spending will decrease future production and cash flow available for distributions; (ii) reducing cash distributions to Unitholders may reduce the trading price or value of the Trust Units in the

market; and (iii) we may not be able to execute an attractive acquisition. In addition, if the current commodity price environment continues, we may be required to further revise our strategy, and any further changes may adversely affect the cash distributions to Unitholders or the value or trading price of the Trust Units.

Distributions on our Trust Units are variable and may be reduced or suspended entirely.

The actual cash flow available for distribution to Unitholders is dependent on the amount of cash flow paid to the Trust by its Operating Entities and can vary significantly from period to period for a number of reasons, including among other things: (i) the Operating Entities' operational and financial performance (including fluctuations in the quantity of their oil, NGLs and natural gas production and the sales price that they realize for such production (after hedging contract receipts and payments)); (ii) fluctuations in the costs to produce oil, NGLs and natural gas, including royalty burdens, and to administer and manage the Trust and its subsidiaries; (iii) the amount of cash required or retained for debt service or repayment; (iv) amounts required to fund capital expenditures and working capital requirements; and (v) foreign currency exchange rates and interest rates. Certain of these amounts are, in part, subject to the discretion of the Board of Directors, which regularly evaluates the Trust's distribution payout with respect to anticipated cash flows, debt levels, capital expenditures plans and amounts to be retained to fund acquisitions and expenditures. In addition, our level of distribution per Trust Unit will be affected by the number of outstanding Trust Units and other securities that may be entitled to receive cash distributions, such as any exchangeable shares that our Subsidiaries may issue from time to time. Distributions may be increased, reduced or suspended entirely depending on our operations and the performance of our assets. The market value of the Trust Units may deteriorate if the Trust is unable to meet distribution expectations in the future, and that deterioration may be material.

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

On October 31, 2006, the Federal Minister of Finance proposed the SIFT Tax, which would deny the deduction of distributions at the trust level and subject any income of certain publicly traded mutual fund trusts to tax at rates comparable to the combined federal and provincial corporate tax and to treat such distributions as taxable dividends to the unitholders. On December 21, 2006, the Federal Minister of Finance released draft legislation to implement the SIFT Tax pursuant to which, commencing January 1, 2011 (provided we only experience "normal growth" and no "undue expansion" before then) certain distributions from us which would have otherwise been taxed as ordinary income generally will be characterized as dividends to our Unitholders and will be subject to tax at the corporate rates at the trust level. On June 22, 2007, the legislation received Royal assent. The implementation of the SIFT Tax is expected to result in adverse tax consequences to us and certain Unitholders (including most particularly Unitholders that are tax deferred or non-residents of Canada) and may impact the level of cash distributions from us.

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

The Trust is a taxable entity under the Tax Act and is taxable only on income that is not distributed or distributable to the Unitholders. As the Trust distributes all of its taxable income to the Unitholders pursuant to the Trust Indenture and currently satisfies the requirements of the Tax Act applicable to the Trust, the Trust does not expect to pay income taxes until the earlier of January 1, 2011 or if and when it ceases to be a trust. The SIFT Tax will not impose a tax on distributions from entities, such as the Trust, until January 1, 2011 as long as that the Trust experiences only "normal growth" as set out in the guidelines described below. Commencing in January 2011, the Trust will be liable for tax on all distributions of income paid or payable to Unitholders, which distributions the Trust will no longer be able to deduct in computing its taxable income. The Trust currently has significant tax pools and expects to continue to increase its tax pool base until 2011. Accordingly, it is expected that the Trust will be able to shelter income for a period of time after the application of the SIFT Tax.

As a result, the adverse tax consequences resulting from the SIFT Tax could be borne sooner than January 1, 2011. On December 15, 2006, the Department of Finance issued guidelines with respect to what is meant by "normal growth" in this context. Specifically, the Department of Finance stated that "normal growth" would include equity growth within certain "safe harbour" limits, measured by reference to a SIFT's market capitalization as of the end of trading on October 31, 2006 (which would include only the market value of the SIFT's issued and outstanding publicly-traded trust units, and not any convertible debt, options or other interests convertible into or exchangeable for trust units). Those safe harbour limits are 40% for the period from November 1, 2006 to December 31, 2007, and 20% each for calendar year 2008, 2009 and 2010. Moreover, these limits are cumulative, so that any unused limit for a period carries over into the subsequent period. Additional details of the Department of Finance's guidelines include the following: (i) new equity for these purposes includes units and debt that is convertible into units (and may include other substitutes for equity if attempts are made to develop those); and (ii) replacing debt that was outstanding as of October 31, 2006 with new equity, whether by a conversion into trust units of convertible debentures or otherwise, will not be considered growth for these purposes and will therefore not affect the safe harbour.

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

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

Pursuant to proposed regulations to the Tax Act, the provincial SIFT Tax rate will be based on the general provincial corporate income tax rate in each province in which the Trust has a permanent establishment. For purposes of calculating this component of the tax, the general corporate taxable income allocation formula will be used. Specifically, the Trust's taxable distributions, if any, will be allocated to provinces by taking half of the aggregate of:

·	that proportion of the Trust's taxable distributions, if any, for the year that the Trust's wages and salaries in the province are of its total wages and salaries in Canada; and

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

It is anticipated that the Trust would be considered to have a permanent establishment in Alberta only, where the provincial tax rate in 2011 is expected to be 10%, which will result in an effective tax rate of 26.5% in 2011. Taxable distributions, if any, that are not allocated to any province, would instead be subject to a 10% rate constituting the provincial component.

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

For additional information, see "General Development of the Business – History and Development – Year Ended December 31, 2006 – Changes to Taxation of Income Trusts".

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

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

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

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

In December 2008, the Government of Alberta passed into law a "New Royalty Framework", effective January 1, 2009. The Government of Alberta has offered oil and gas producers a one-time option to select, for a five year period, transitional

royalty rates as an alternative to the New Royalty Framework in respect of certain new wells spud on or after November 19, 2008. Additionally, on March 3, 2009, the Government of Alberta announced a short-term incentive program to encourage the drilling of new wells over the next twelve months, which includes lower initial royalty rates and certain royalty credits. See "Industry Conditions – Provincial Royalties and Incentives - Alberta" and "General Development of the Business – History and Development – Year Ended December 31, 2008 – Revisions to Alberta Royalty Regime". In 2008, approximately 55% of our crude oil and natural gas production was from Alberta Crown leases. Given that we have not yet completed a fiscal period operating under the New Royalty Framework and the fact that the New Royalty Framework is sensitive to commodity price and production levels, it is not possible at this time to determine the full impact of the New Royalty Framework (including the transitional royalty rates and short-term incentives) on our financial condition and operations, and in particular the extent to which the New Royalty Framework could reduce our cash flow, which could in turn reduce the cash otherwise available for distribution by us to our Unitholders. Our reserves and the estimated future net revenue associated therewith, as contained in the reserve reports summarized in this Annual Information Form, reflect the revised royalty rates contemplated by the New Royalty Framework. Any adverse impact on us from the New Royalty Framework will be particularly felt in periods of high to mid-level commodity prices.

We may not be able to achieve the anticipated benefits of acquisitions and the integration of acquisitions may result in the loss of key employees and the disruption of on-going business relationships.

We make acquisitions and dispositions of businesses and assets in the ordinary course of business. Achieving the benefits of acquisitions depends in part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner, as well as our ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with ours. The integration of acquired businesses may require substantial management effort, time and resources and may divert management's focus from other strategic opportunities and operational matters, and may also result in the loss of key employees, the disruption of on-going business, supplier, customer and employee relationships and reportable deficiencies in internal controls over financial reporting or information technology general controls. We continually assess the value and contribution of services provided and assets required to provide such services. In this regard, non-core assets are periodically disposed of, so that we can focus our efforts and resources more efficiently. Depending on the state of the market for such non-core assets, certain of our non-core assets, if disposed of, could be expected to realize less than their carrying value in our financial statements.

The incorrect assessment of value at the time of acquisitions could adversely affect the value of our Trust Units and distributions to our Unitholders.

Acquisitions of oil and gas properties or companies will be based in large part on engineering and economic assessments made by independent engineers. These assessments include a series of assumptions regarding such factors as recoverability and marketability of oil and gas, future prices of oil and gas and operating costs, future capital expenditures and royalties and other government levies which will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond our control. All such assessments involve a measure of geological and engineering uncertainty that could result in lower production and reserves than anticipated. If actual reserves or production are less than we expect, our funds flow from operations and distributions to Unitholders could be negatively affected.

Our inability to manage growth could adversely affect our business and our Unitholders.

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

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

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

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

Amounts paid in respect of interest and principal on debt we have incurred will reduce funds available for distributions. Variations in interest rates and any scheduled principal repayments could result in significant changes in the amount required to be applied to debt service before payment of the NPIs. Certain covenants in the agreements with our lenders may also limit distributions in certain circumstances. Increases in interest rates could also result in decreases to the market value of our Trust Units. Although we believe our credit facilities and other debt instruments will be sufficient for our immediate requirements, there can be no assurance that the amount will be adequate for our future financial obligations or that additional funds will be able to be obtained.

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

Changes in the regulation of the oil and gas industry may adversely affect our business.

Oil and natural gas operations (including exploration, production, pricing, marketing and transportation operations) are subject to extensive controls and regulations imposed by various levels of government that may be changed or amended from time to time. We have no control over these changes and amendments and the impact that they may have on us, and any such impact could be material and adverse. See "Industry Conditions" herein, including in respect of the Government of Alberta's NRF and related shallow rights reversion program.

Our operations require licenses from various governmental authorities. There can be no assurance that we will be able to obtain all necessary licenses and permits that may be required to carry out exploration and development at our projects.

Acquiring, developing and exploring for oil and natural gas involves many risks. Losses resulting from the occurrence of one or more of these risks may adversely affect our business and thus the value of our Trust Units and distributions to our Unitholders.

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

·	encountering unexpected formations or pressures;

·	premature declines of reservoirs;

·	blow-outs, equipment failures and other accidents;

·	sour gas releases;

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

·	adverse weather conditions; and

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

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

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

Continuing production from a property, and to some extent the marketing of production therefrom, largely depend upon the ability of the operator of the property or related facilities. Operating costs on most properties have increased over recent years. To the extent the operator fails to perform these functions properly, operating income will be reduced. Payments from production generally flow through the operator and there is a risk of delay and additional expense in receiving such revenues if the operator becomes insolvent.

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

Although title reviews may be conducted prior to the purchase of oil and natural gas producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat our claim, which could result in a reduction of the revenue received by us and consequently the funds flow available for distribution to Unitholders.

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

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

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

Our involvement in the exploration and development of oil and natural gas properties could subject us to liability for pollution, blowouts, property damage, personal injury or other hazards. Prior to commencing operations, we obtain insurance in accordance with industry standards to address certain of these risks. Such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not, in all circumstances, be insurable or, in certain circumstances, we may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. The payment of such uninsured liabilities would reduce the funds available to us. The occurrence of a significant event that we are not fully insured against, or the insolvency of the insurer of such event, could have a material adverse effect on our financial position, results of operations or prospects and will reduce funds flow otherwise distributable by us.

Distributions might be reduced during periods in which we make capital expenditures using our funds flow from operations, which could negatively affect the market price of our Trust Units.

Future oil and natural gas reserves and hence revenues are highly dependent on our success in exploiting existing properties and acquiring additional reserves. We also intend to distribute approximately 60% to 70% of our net funds flow to Unitholders rather than reinvesting it in reserve additions and production growth or maintenance. Accordingly, if external sources of capital, including the issuance of additional Trust Units, become limited or unavailable on commercially reasonable terms, our ability to make the necessary capital investments to maintain or expand our oil and natural gas reserves will be impaired. To the extent that we are required to use funds flow to finance capital expenditures or property acquisitions, the level of funds flow available for distribution to Unitholders will be reduced. Additionally, we cannot guarantee that we will be successful in exploring for and developing additional reserves or acquiring additional reserves on terms that meet our investment objectives. Without these reserve additions, our reserves will decline and as a consequence,

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

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

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

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

The operations and expertise of our management are currently focused on oil and gas production and exploration and development in the Western Canadian Sedimentary Basin and, since the completion of the Canetic Acquisition, in North Dakota, Montana and Wyoming in the United States. In the future, we may acquire oil and gas properties outside these geographic areas. In addition, the Trust Indenture does not limit our activities to oil and gas production and development, and we could acquire other energy related assets, such as additional oil and natural gas processing plants, upgraders or pipelines. Expansion of our activities into new areas may present new additional risks or alternatively, significantly increase the exposure to one or more of the present risk factors that may result in our future operational and financial conditions being adversely affected.

Non-Residents of Canada may be subject to additional taxation by Canadian or foreign governments that may adversely affect them.

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

Additionally, the reduced "Qualified Dividend" rate of 15% tax which has applied to our distributions under current U.S. tax laws is scheduled to expire at the end of 2010 and there is no assurance that this reduced tax rate will be renewed by the U.S. government at such time.

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

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

The Trust Units do not represent a traditional investment in the oil and natural gas sector and should not be viewed by investors as shares in PWPL. The Trust Units represent a fractional interest in our assets. As holders of Trust Units, Unitholders will not have the statutory rights normally associated with ownership 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 Trust Indenture. In addition, trusts are not defined as recognized entities within the definitions of legislation such as the Bankruptcy and Insolvency Act (Canada), the Companies' Creditors Arrangement Act (Canada) and in some cases the Winding Up and Restructuring Act (Canada). As a result, in the event of an insolvency or restructuring, a Unitholder's position as such may be quite different than that of a shareholder of a corporation. Our sole assets are the NPIs and other investments in securities of our Operating Entities, including the Internal Notes. The price per Trust Unit is a function of anticipated income available for distributions, the oil and gas assets acquired by us and our ability to effect long-term growth in the value of our assets. The market price of the Trust Units is sensitive to a variety of market conditions including, but not

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

The Trust Units are not "deposits" within the meaning of the Canada Deposit Insurance Corporation Act (Canada) and are not insured under the provisions of that Act or any other legislation. Furthermore, we are not a trust company and, accordingly, we are not registered under any trust and loan company legislation as we do not carry on or intend to carry on the business of a trust company.

The limited liability of Unitholders is uncertain.

The Trust Indenture provides that no Unitholder will be subject to any liability in connection with our obligations and affairs and, in the event that a court determines Unitholders are subject to any such liabilities, the liabilities will be enforceable only against, and will be satisfied only out of, our assets. Pursuant to the Trust Indenture, we will indemnify and hold harmless each Unitholder from any costs, damages, liabilities, expenses, charges and losses suffered by a Unitholder resulting from or arising out of such Unitholder not having such limited liability.

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

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

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

We use enhanced oil recovery methods that are subject to significant risk factors which could lead to the delay or cancellation of some or all of our enhanced oil recovery projects, which could adversely affect the market price of our Trust Units and our distributions to Unitholders.

Penn West utilizes new drilling and completion technologies, including horizontal multi fracture completions, intended to increase the resource recovery from known producing oil and natural gas fields. There is potential Penn West may not realize the anticipated increase in resource recovery from the employment of such techniques due to particular reservoir characteristics or other adverse factors. We currently use conventional artificial lift technology to recover heavy oil from bitumen deposits at our Peace River oil sands project. The potential or planned use of enhanced oil recovery ("EOR") methods such as steam injection (Steam Assisted Gravity Drainage, Cyclical Steam Stimulation and Steam Flooding), solvent injection and firefloods to increase the ultimate recovery of oil resources in place are subject to significant risk factors. These factors, which could lead to a delayed or cancelled EOR application in the Peace River oil sands project, include but are not limited to the following:

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

·	changing engineering and technical conditions (ability to apply EOR methods to the reservoir and the production response thereto);

·	the large development program may need to spread over a longer time period than initially planned due to requirement to allocate capital expenditures to different periods;

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

·	environmental regulations, relating to such items as green house gas emissions and access to water, which could impact capital and operating costs; and

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

The use or potential or planned use of carbon dioxide miscible flooding to increase the oil recovery from large legacy oil pools such as Pembina and South Swan Hills is subject to significant risk factors which could lead to the delay or cancellation of some or all of these projects. These factors include, but are not limited to:

·	carbon dioxide infrastructure (the capture and transportation of the miscible agent to us at an economic cost);

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

·	changing engineering and technical conditions (ability to apply carbon dioxide EOR methods to the reservoir and the production response thereto);

·	the large development program may need to be spread over a longer time period than planned due to capital allocation requirements;

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

·	surface access and deliverability issues (weather, pipeline, road and processing matters); and

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

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

Unitholders may suffer dilution.

We may make future acquisitions or enter into financings or other transactions involving the issuance of our securities, which may be dilutive to Unitholders. In addition, we may determine to redeem the currently outstanding Convertible Debentures for Trust Units or to settle the interest and/or pay the redemption price at maturity of such Convertible Debentures by issuing additional Trust Units. Unitholders may suffer dilution in the event of any such issuance of Trust Units.

Seasonal factors and unexpected weather patterns may lead to declines in our activities and thereby adversely affect our business, the market price of our Trust Units and distributions to our Unitholders.

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

Changes to Canadian federal income tax legislation or other factors could result in us losing our mutual fund trust status, which would have an adverse effect on the market price of the Trust Units and distributions to our Unitholders.

In order for us to maintain our status as a mutual fund trust under the Tax Act, we must not be established or maintained primarily for the benefit of Non-Residents unless we satisfy the requirements of certain exceptions. The Trust Indenture provides that we will use our best commercial efforts to maintain our status as a mutual fund trust under the Tax Act. Generally speaking, the Tax Act provides that a trust will permanently lose its "mutual fund trust" status (which is essential to the income trust structure) if it is established or maintained primarily for the benefit of Non-Residents (which is generally interpreted to mean that the majority of unitholders must not be Non-Residents), unless at the relevant time, "all or substantially all" of the trust's property consists of property other than taxable Canadian property (the "TCP Exception"). Based on information obtained by us through our transfer agent and financial intermediaries, in February 2009, we estimate that approximately 61% of our issued and outstanding Trust Units were held by Non-Residents. We have determined that we currently meet the requirement of the TCP Exception, and as a result, the Trust Indenture does not currently have a specific limit on the percentage of Trust Units that may be owned by Non-Residents.

There is no assurance that the TCP Exception will continue to be available to us or that the Government of Canada will not introduce new changes or proposals to tax regulations directed at Non-Resident ownership which, given our level of

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

If we cease to qualify as a "mutual fund trust" under the Canadian tax laws, adverse tax consequences would arise for the Trust and our Unitholders.

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

We would be taxed on certain types of income distributed to Unitholders, including income generated by the royalties we hold. Payment of this tax may have adverse consequences for some Unitholders, particularly Unitholders that are not residents of Canada and residents of Canada that are otherwise exempt from Canadian income tax or hold their Trust Units in a tax deferred account.

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

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

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

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

There might not always be an active trading market in the United States and/or Canada for the Trust Units and/or the Convertible Debentures.

While there is currently an active trading market for the Trust Units in both the United States and Canada, we cannot guarantee that an active trading market will be sustained in either country. If an active trading market in the Trust Units is not sustained, the trading liquidity of the Trust Units will be limited and the market value of the Trust Units may be reduced.

There is not currently an active trading market for the Convertible Debentures in Canada, and we cannot guarantee that an active trading market will develop. If an active trading market in the Convertible Debentures does not develop, the trading liquidity of the Convertible Debentures will remain limited and the market value of the Convertible Debentures may be adversely affected.

The economic impact on us of claims of aboriginal title is unknown.

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

Our exploration and development activities may be delayed if drilling and related equipment is unavailable or if access to drilling locations is restricted. These events could have an adverse impact on our business.

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

Our directors and management may have conflicts of interest that may create incentives for them to act contrary to or in competition with the interests of our Unitholders.

The directors and officers of PWPL are engaged in, and will continue to engage in, other activities in the oil and natural gas industry and, as a result of these and other activities, the directors and officers of PWPL may become subject to conflicts of interest. The ABCA provides that in the event that a director has an interest in a contract or proposed contract or agreement, the director must disclose his interest in such contract or agreement and must refrain from voting on any matter in respect of such contract or agreement unless otherwise provided under the ABCA. To the extent that conflicts of interest arise, such conflicts will be resolved in accordance with the provisions of the ABCA and our Code of Business Conduct and Ethics.

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

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

The ability of residents of the United States to enforce civil remedies against us and our directors, officers and experts may be limited.

Both the Trust and PWPL are organized under the laws of Alberta, Canada and our respective principal places of business are in Canada. Most of our directors and all of our officers and the experts named herein are residents of Canada, and a substantial portion of our assets and all or a substantial portion of the assets of such persons are located outside the United States. As a result, it may be difficult for investors in the United States to effect service of process within the United States upon those directors, officers and experts who are not residents of the United States or to enforce against them judgments of United States courts based upon civil liability under the United States federal securities laws or the securities laws of any state within the United States. There is doubt as to the enforceability in Canada against us or against any of our directors, officers or experts who are not residents of the United States, in original actions or in actions for enforcement of judgments of United States courts of liabilities based solely upon the United States federal securities laws or the securities laws of any state within the United States.

Canadian and United States practices differ in reporting reserves and production and our estimates may not be comparable to those of companies in the United States.

We report our production and reserve quantities in accordance with Canadian practices and specifically in accordance with NI 51-101. These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the SEC by companies in the United States.

The SEC generally permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves after the deduction of royalties and interests of others which are those reserves that a company has demonstrated by actual production or conclusive formation tests to be economically producible under existing economic and operating conditions. The

securities regulatory authorities in Canada have adopted NI 51-101, which imposes oil and gas disclosure standards for Canadian public issuers engaged in oil and gas activities. NI 51-101 permits oil and gas issuers, in their filings with Canadian securities regulators, to disclose not only proved reserves but also probable reserves, and to disclose reserves and production on a gross basis before deducting royalties. Probable reserves are of a higher risk and are less likely to be accurately estimated or recovered than proved reserves. Because we are permitted to disclose reserves in accordance with Canadian disclosure requirements, we have disclosed herein reserves designated as "probable reserves". If required to be prepared in accordance with U.S. disclosure requirements, the SEC's guidelines would prohibit reserves in this category from being included. Moreover, as permitted by NI 51-101, we have determined and disclosed the net present value of future net revenue from our reserves using only forecast prices and costs. The SEC does not permit the disclosure of the net present value of future net revenue from reserves based on forecast prices and costs and generally requires that prices and costs be held constant at levels in effect at the date of the reserve report.

Our distributions are declared in Canadian dollars and Non-Resident investors are therefore subject to foreign exchange risk that could adversely affect the amount of distributions received by them.

Our distributions are declared in Canadian dollars and converted to foreign denominated currencies at the spot exchange rate at the time of payment. As a consequence, investors are subject to foreign exchange risk. To the extent that the Canadian dollar weakens with respect to their currency, the amount of the distribution will be reduced when converted to their home currency.

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

Canadian GAAP requires that management apply certain accounting policies and make certain estimates and assumptions that affect reported amounts in our consolidated financial statements. Under Canadian GAAP, the amounts at which petroleum and natural gas property and equipment are carried as net assets on the balance sheet are subject to a cost-recovery or "ceiling" test, which is based in part upon estimated future net funds flows from reserves. If net capitalized costs exceed the estimated recoverable amounts, we will have to charge the amount of the excess to net income. A decline in the net value of oil and natural gas properties could cause capitalized costs to exceed the cost ceiling, resulting in a non-cash charge against net income. The value of oil and gas properties is highly dependent upon the prices of oil and natural gas.

Under U.S. GAAP, the estimated recoverable amounts are calculated based on estimated future net funds flows from proved reserves discounted at 10% and using commodity prices in effect on the balance sheet date. The use of discounting and constant prices results in a greater likelihood of a write-down under U.S. GAAP than Canadian GAAP.

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

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

A decrease in the fair market value of our hedging instruments could result in a non-cash charge against our income under Canadian GAAP.

Canadian GAAP in respect of accounting for financial instruments may result in non-cash charges against income 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 of fluctuations in commodity prices and/or foreign exchange rates may result in a non-cash charge against income.

United States Unitholders may be subject to passive foreign investment company rules.

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

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

Alternatively, a United States Unitholder that makes a "qualified electing fund" election generally will be subject to United States federal income tax on such United States Unitholder's pro rata share of the Trust's "net capital gain" and "ordinary earnings" (calculated under United States federal income tax rules), regardless of whether such amounts are actually distributed by the Trust. United States Unitholders should be aware that there can be no assurance that the Trust will satisfy record keeping requirements or that it will supply United States Unitholders with required information under the "qualified electing fund" rules in the event that the Trust is a PFIC and a United States Unitholder wishes to make a "qualified electing fund" election. As a second alternative, a United States Unitholder may make a "mark-to-market election" if the Trust is a PFIC and the Trust Units are marketable stock regularly traded on a securities exchange or other market the United States Secretary of the Treasury determines as adequate. A retroactive election is permitted only in accordance with the United States Treasury Regulations and in some circumstances will require the permission of the United States Commissioner of the Internal Revenue Service. Additionally, United States holders will not be able to make the "mark-to-market election" with respect to the Trust's Operating Entities should they be determined to be PFICs. A United States Unitholder that makes a "mark-to-market election" generally will include in gross income, for each taxable year in which the Trust is a PFIC, an amount equal to the excess, if any, of (a) the fair market value of the Trust Units as of the close of such taxable year over (b) such United States Unitholder's tax basis in such Trust Units. United States Unitholders are strongly urged to consult their own tax advisors regarding the United States federal income tax consequences of the Trust's possible classification as a PFIC and the consequences of such classification.

We are uncertain what impact the conversion to International Financial Reporting Standards will have on us.

The Accounting Standards Board of the Canadian Institute of Chartered Accountants has announced that Canadian publicly accountable enterprises are required to adopt International Financial Reporting Standards ("IFRS"), as issued by the International Accounting Standards Board, effective January 1, 2011. IFRS will require increased financial statement disclosure as compared to Canadian GAAP. Although IFRS uses a conceptual framework similar to Canadian GAAP, differences in accounting policies will need to be addressed by us. We are currently considering the impact a conversion to IFRS will have on us, including on our financial statements.

We cannot assure you that the distributions you receive over the life of your investment will meet or exceed your initial capital investment, which is at risk.

Trust Units will have no value when the underlying petroleum and natural gas properties can no longer be economically 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 yield securities, where investors are entitled to a full return of the principal amount of debt on maturity in addition to a return on investment through interest payments. Distributions can represent a return of or a return on Unitholders' capital.

Your redemption right as a Unitholder is limited.

Unitholders have a limited right to require us to repurchase their Trust Units, which is referred to as a redemption right. See "Information Relating to Penn West – Trust Indenture – Right of Redemption" herein for details of the redemption right. It is anticipated that the redemption right will not be the primary mechanism for Unitholders to liquidate their investment. The right to receive cash in connection with a redemption is subject to limitations. Any securities which may be distributed in specie to Unitholders in connection with a redemption may not be listed on any stock exchange and a market may not develop for such securities. In addition, there may be resale restrictions imposed by law upon the recipients of the securities pursuant to the redemption right.

MATERIAL CONTRACTS

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

(a)	the Trust Indenture described under "Information Relating to Penn West – Trust Indenture";

(b)	the Administration Agreement referred to under "Information Relating to Penn West – Trust Indenture – Our Management" and "Corporate Governance";

(c)	the Debenture Indentures described under "Information Relating to Penn West – Convertible Debentures";

(d)

the credit agreement dated January 10, 2008 among PWPL and certain lenders and other parties in respect of Penn West's $4 billion syndicated credit facility, which agreement is described in Note 6 to Penn West's audited comparative consolidated financial statements for the year ended December 31, 2008, which note is incorporated by reference herein;

(e)

the note purchase agreement dated May 31, 2007 among PWPL and the holders of PWPL's US$475 million principal amount of 2007 Senior Notes, which agreement is described in Note 6 to Penn West's audited comparative consolidated financial statements for the year ended December 31, 2008, which note is incorporated by reference herein. See also "General Development of the Business – History and Development - Year Ended December 31, 2007 – Private Placement of 2007 Senior Notes";

(f)

the note purchase agreement dated May 29, 2008 among PWPL and the holders of PWPL's US$480 million and Cdn$30 million principal amount of 2008 Senior Notes, which agreement is described in Note 6 to Penn West's audited comparative consolidated financial statements for the year ended December 31, 2008, which note is incorporated by reference herein. See also "General Development of the Business – History and Development - Year Ended December 31, 2008 – Private Placement of 2008 Senior Notes"; and

(g)

the note purchase agreement dated July 31, 2008 among PWPL and the holders of PWPL's £57 million principal amount of 2008 Pounds Sterling Senior Notes, which agreement is described in Note 6 to Penn West's audited comparative consolidated financial statements for the year ended December 31, 2008, which note is incorporated by reference herein. See also "General Development of the Business – History and Development - Year Ended December 31, 2008 – Private Placement of 2008 Pounds Sterling Senior Notes".

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

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

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

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

There were no: (i) penalties or sanctions imposed against Penn West by a court relating to securities legislation or by a security regulatory authority during the most recently completed financial year; (ii) any other penalties or sanctions imposed by a court or regulatory body against Penn West that would likely be considered important to a reasonable investor in making an investment decision; or (iii) settlement agreements Penn West entered into before a court relating to securities legislation or with a securities regulatory authority during Penn West's most recently completed financial year.

TRANSFER AGENTS AND REGISTRARS

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

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

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

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

INTERESTS OF EXPERTS

There is no person or company whose profession or business gives authority to a report, valuation, statement or opinion made by such person or company and who is named as having prepared or certified a report, valuation, statement or opinion described or included in a filing, or referred to in a filing, made under National Instrument 51-102 by us during, or related to, our most recently completed financial year, other than GLJ and Sproule, our independent engineering evaluators (GLJ and Sproule each an "Engineer" and collectively, the "Engineers"), KPMG LLP ("KPMG"), our auditors, and Deloitte & Touche LLP, Canetic's former auditors.

The registered or beneficial interests, direct or indirect, in any securities or other property of Penn West or of one of its associates or affiliates: (i) held by an Engineer and by the "designated professionals" (as defined in National Instrument 51-102) of the Engineer, when that Engineer prepared the report, valuation, statement or opinion referred to above; (ii) received by an Engineer and by the "designated professionals" of that Engineer, after the time specified above; or (iii) to be received by an Engineer and by the "designated professionals" of that Engineer; in each case, represented less than 1% of each class of our outstanding securities.

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

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

ADDITIONAL INFORMATION

Additional information relating to Penn West may be found on SEDAR at www.sedar.com and on EDGAR at www.sec.gov. Additional information, including directors' and officers' remuneration and indebtedness, principal holders of Penn West's securities and securities authorized for issuance under equity compensation plans, is contained in Penn West's information circular for its most recent annual meeting of Unitholders that involves the election of directors. Additional financial information is provided in Penn West's financial statements and management's discussion and analysis for its most recently completed financial year.

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

APPENDIX A-1

REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION

(Form 51-101F3)

Management of Penn West Petroleum Ltd. ("PWPL") on behalf of Penn West Energy Trust (collectively "Penn West") is responsible for the preparation and disclosure of information with respect to Penn West's oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data which are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2008, estimated using forecast prices and costs.

Independent qualified reserves evaluators (or in some cases qualified reserves auditors) have evaluated (or in some cases audited) Penn West's reserves data. The report of the independent qualified reserves evaluators (or in some cases qualified reserves auditors) is presented below.

The Reserves Committee of the Board of Directors of PWPL has:

(a)

reviewed Penn West's procedures for providing information to the independent qualified reserves evaluators (or in some cases qualified reserves auditors);

(b)

met with the independent qualified reserves evaluators (or in some cases qualified reserves auditors) to determine whether any restrictions affected the ability of the independent qualified reserves evaluators (or in some cases qualified reserves auditors) to report without reservation; and

(c)

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

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

(a)

the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information;

(b)

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

(c)

the content and filing of this report.

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

(signed) William E. Andrew	(signed) Murray R. Nunns
Chief Executive Officer	President and Chief Operating Officer

(signed) Daryl Gilbert	(signed) Jack Schanck
Director and Chairman of the Reserves Committee	Director and Member of the Reserves Committee

September 15, 2009

APPENDIX A-2

REPORT ON RESERVES DATA

(Form 51-101 F2)

To the Board of Directors of Penn West Petroleum Ltd. ("PWPL") on behalf of Penn West Energy Trust (collectively "Penn West"):

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

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

We carried out our evaluation (or in some case or audit) in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

Those standards require that we plan and perform an evaluation (or in some cases an audit) to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation or audit also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.

The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of Penn West evaluated and audited by us for the year ended December 31, 2008, and identifies the respective portions thereof that we have evaluated and audited and reported on to PWPL's Board of Directors:

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

6.	In our opinion, the reserves data respectively evaluated or audited by us have, in all material respects, been determined and are in accordance with the COGE Handbook. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.

7.	We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.

8.	Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.

Executed as to our report referred to above:

(signed) GLJ Petroleum Consultants Ltd.

Calgary, Alberta, Canada

September 15, 2009

(signed) Sproule Associates Limited

Calgary, Alberta, Canada

September 15, 2009

APPENDIX A-3

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

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

Disclosure of Reserves Data

The reserves data set forth below is based upon: (i) an evaluation prepared by GLJ with an effective date of December 31, 2008 contained in the GLJ Report dated February 24, 2009; and (ii) an evaluation and audit prepared by Sproule with an effective date of December 31, 2008 contained in the Sproule Report dated February 26, 2009. The reserves data summarizes our oil, natural gas liquids and natural gas reserves and the net present values of future net revenue from these reserves using forecast prices and costs, not including the impact of any hedging activities. The reserves data conforms with the requirements of NI 51-101. We engaged GLJ to evaluate approximately 60% of our proved and proved plus probable reserves. We engaged Sproule to evaluate approximately 32% and to audit approximately 8% of our proved and proved plus probable reserves. See also "Notes to Reserve Data Tables" below.

The Engineering Reports include Alberta crown royalties in accordance with the Alberta New Royalty Framework (NRF) which passed provincial legislation in December 2008. The Engineering Reports do not take into account either the transitional royalty rate program announced by the Government of Alberta on November 19, 2008 or the new royalty incentive program announced by the Government of Alberta on March 3, 2009. See "Industry Conditions – Provincial Royalties and Incentives – Alberta" for details of these programs.

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

It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserves estimates of crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquid reserves may be greater than or less than the estimates provided herein. For more information as to the risks involved, see "Risk Factors".

Reserves Data (Forecast Prices and Costs)

SUMMARY OF OIL AND GAS RESERVES

as of December 31, 2008

FORECAST PRICES AND COSTS

	RESERVES
	LIGHT AND MEDIUM OIL					HEAVY OIL
RESERVES CATEGORY		Gross (MMbbl)		Net (MMbbl)		Gross (MMbbl)		Net (MMbbl)

PROVED
Developed Producing			221		190		53		49
Developed Non-Producing			5		4		3		3
Undeveloped			37		31		6		5
TOTAL PROVED			263		225		62		57

PROBABLE			89		74		31		27
TOTAL PROVED PLUS PROBABLE			352		298		94		84

	RESERVES
		NATURAL GAS				NATURAL GAS LIQUIDS
RESERVES CATEGORY		Gross (Bcf)		Net (Bcf)		Gross (MMbbl)		Net (MMbbl)

PROVED
Developed Producing			947		811		25		18
Developed Non-Producing			65		52		1		1
Undeveloped			62		54		1		1
TOTAL PROVED			1,074		916		27		19

PROBABLE			402		337		9		7
TOTAL PROVED PLUS PROBABLE			1,476		1,253		37		26

	RESERVES
	TOTAL OIL EQUIVALENT
RESERVES CATEGORY	Gross (MMboe)		Net (MMboe)

PROVED
Developed Producing		457		392
Developed Non-Producing		20		16
Undeveloped		54		46
TOTAL PROVED		532		454

PROBABLE		197		164
TOTAL PROVED PLUS PROBABLE		729		617

NET PRESENT VALUES OF FUTURE NET REVENUE

BEFORE INCOME TAXES DISCOUNTED AT (%/year)

FORECAST PRICES AND COSTS

											Unit Value Before Income Tax Discounted at 10%/year(1)
RESERVES CATEGORY	0% (MM$)		5% (MM$)		10% (MM$)		15% (MM$)		20% (MM$)		($/bbl)		($/Mcf)

PROVED
Developed Producing		16,949		11,497		8,827		7,231		6,161		22.52		3.75
Developed Non-Producing		679		462		354		288		242		22.12		3.69
Undeveloped		2,117		1,107		643		390		238		14.08		2.35
TOTAL PROVED		19,746		13,066		9,824		7,909		6,641		21.65		3.61

PROBABLE		9,058		4,521		2,777		1,914		1,414		16.96		2.83

TOTAL PROVED PLUS PROBABLE		28,803		17,587		12,602		9,823		8,056		20.44		3.41

Note:

(1)	The unit values are based on net reserve volumes.

NET PRESENT VALUES OF FUTURE NET REVENUE

AFTER INCOME TAXES DISCOUNTED AT (%/year)

FORECAST PRICES AND COSTS

RESERVES CATEGORY	0% (MM$)		5% (MM$)		10% (MM$)		15% (MM$)		20% (MM$)

PROVED
Developed Producing		14,986		10,528		8,264		6,873		5,920
Developed Non-Producing		530		372		293		244		209
Undeveloped		1,594		836		480		284		164
TOTAL PROVED		17,111		11,735		9,038		7,401		6,293

PROBABLE		6,634		3,352		2,085		1,455		1,089

TOTAL PROVED PLUS PROBABLE		23,744		15,087		11,123		8,856		7,383

TOTAL FUTURE NET REVENUE

(UNDISCOUNTED)

as of December 31, 2008

FORECAST PRICES AND COSTS

RESERVES CATEGORY	REVENUE (MM$)		ROYALTIES (MM$)		OPERATING COSTS (MM$)		DEVELOPMENT COSTS (MM$)		ABANDONMENT AND RECLAMATION COSTS (MM$)		FUTURE NET REVENUE BEFORE INCOME TAXES (MM$)		INCOME TAXES (MM$)		FUTURE NET REVENUE AFTER INCOME TAXES (MM$)

Proved Reserves		42,485		6,507		13,977		1,120		1,135		19,746		2,635		17,111

Proved Plus Probable Reserves		60,421		9,695		18,873		1,760		1,291		28,803		5,059		23,744

FUTURE NET REVENUE

BY PRODUCTION GROUP

as of December 31, 2008

FORECAST PRICES AND COSTS

		FUTURE NET REVENUE BEFORE INCOME TAXES (discounted at		UNIT VALUE(3)
RESERVES CATEGORY	PRODUCTION GROUP	10%/year) (MM$)		($/bbl)		($/Mcf)

Proved Reserves	Light and Medium Crude Oil(1)		4,263		22.54		3.76
	Heavy Oil(1)		1,096		17.95		2.99
	Natural Gas(2)		4,369		22.17		3.70
	Non-Conventional Oil and Gas Activities		97		14.86		2.48
	TOTAL		9,824		21.65		3.61

Proved Plus Probable Reserves	Light and Medium Crude Oil(1)		5,196		21.30		3.55
	Heavy Oil(1)		1,573		17.63		2.94
	Natural Gas(2)		5,672		20.86		3.48
	Non-Conventional Oil and Gas Activities		161		13.85		2.31
	TOTAL		12,602		20.44		3.41

Notes:

(1)	Including solution gas and other by-products.

(2)	Including by-products but excluding solution gas.

(3)	Other company revenue and costs not related to a specific production group have been allocated proportionately to each production group. Unit values are based on net reserve volumes.

Notes to Reserves Data Tables

1.	Columns may not add due to rounding.

2.	The crude oil, natural gas liquids and natural gas reserves estimates presented in the Engineering Reports are based on the definitions and guidelines contained in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook"). A summary of those definitions are set forth below:

Reserves Categories

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

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

(b)	the use of established technology; and

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

Reserves are classified according to the degree of certainty associated with the estimates.

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

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

Other criteria that must also be met for the classification of reserves are provided in the COGE Handbook.

Development and Production Status

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

(f)

Developed reserves are those reserves that are 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 reserves on production. The developed category may be subdivided into producing and non-producing.

(i)

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

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

(g)

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

In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions above are applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers

to the highest level sum of individual entity estimates for which reserves estimates are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

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

(b)	at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

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

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

3.	Forecast prices and costs

NI 51-101 defines "forecast prices and costs" as future prices and costs that are: (i) generally acceptable as being a reasonable outlook of the future; and (ii) if, and only to the extent that, there are fixed or presently determinable future prices or costs to which we are legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in subparagraph (i).

The forecast cost and price assumptions include increases in wellhead selling prices and take into account inflation with respect to future operating and capital costs. Crude oil, natural gas and natural gas liquids benchmark reference pricing, as at December 31, 2008, inflation and exchange rates utilized in the Engineering Reports were as set forth below. The price assumptions set forth below were provided by GLJ and Sproule.

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS

as of December 31, 2008

FORECAST PRICES AND COSTS

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

Notes:

(1)	Inflation rates for forecasting prices and costs.

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

Weighted average actual prices realized, including hedging activities, for the year ended December 31, 2008 were $8.04/Mcf for natural gas, $81.02/bbl for light and medium crude oil, $74.55/bbl for heavy oil and $68.41/bbl for natural gas liquids.

4.	Future Development Costs

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

	Forecast Prices and Costs
Year	Proved Reserves (MM$)		Proved Plus Probable Reserves (MM$)

2009		321		463
2010		266		397
2011		151		234
2012		109		182
2013		82		132
Total: Undiscounted for all years		1,120		1,760

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

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

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

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

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

7.	All factual data supplied to GLJ and Sproule was accepted as represented. No field inspection was conducted.

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

Reconciliations of Changes in Reserves

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

RECONCILIATION OF

COMPANY GROSS RESERVES

BY PRODUCT TYPE

FORECAST PRICES AND COSTS

	LIGHT AND MEDIUM OIL(2)									HEAVY OIL(2)									NATURAL GAS(2)
FACTORS	Gross Proved (MMbbl)			Gross Probable (MMbbl)			Gross Proved Plus Probable (MMbbl)			Gross Proved (MMbbl)			Gross Probable (MMbbl)			Gross Proved Plus Probable (MMbbl)			Gross Proved (Bcf)			Gross Probable (Bcf)			Gross Proved Plus Probable (Bcf)

December 31, 2007		190			57			248			45			16			62			703			198			901

Extensions		6			3			9			1			2			4			22			9			31
Improved Recovery(1)		4			1			5			6			13			18			16			7			23
Technical Revisions		2			(2	)		(1	)		3			(6	)		(2	)		13			(1	)		12
Discoveries		-			-			-			-			-			-			3			1			4
Acquisitions		85			30			114			13			4			17			495			186			681
Dispositions		-			-			(1	)		-			-			-			(15	)		(5	)		(19	)
Economic Factors		2			1			3			4			2			6			17			7			24
Production		(26	)		-			(26	)		(10	)		-			(10	)		(179	)		-			(179	)

December 31, 2008		263			89			352			62			31			94			1,074			402			1,476

Note:

(1)	Improved recovery includes the following infill drilling:

Infill Drilling

	NATURAL GAS LIQUIDS(2)								TOTAL OIL EQUIVALENT(2)
FACTORS	Gross Proved (MMbbl)			Gross Probable (MMbbl)		Gross Proved Plus Probable (MMbbl)			Gross Proved (MMboe)			Gross Probable (MMboe)			Gross Proved Plus Probable (MMboe)

December 31, 2007		17			5		22			370			112			482

Extensions		-			-		-			11			7			18
Improved Recovery(1)		-			-		-			13			15			28
Technical Revisions		-			-		-			7			(9	)		(1	)
Discoveries		-			-		-			-			-			1
Acquisitions		13			5		18			193			69			262
Dispositions		-			-		-			(3	)		(1	)		(4	)
Economic Factors		-			-		-			9			4			13
Production		(4	)		-		(4	)		(69	)		-			(69	)

December 31, 2008		27			9		37			532			197			729

Notes:

(1)	Improved recovery includes the following infill drilling:

Infill Drilling

(2)	Columns may not add due to rounding.

Additional Information Relating to Reserves Data

Undeveloped Reserves

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

In some cases, it will take longer than two years to develop these reserves. Penn West plans to develop approximately one-half of the proved undeveloped reserves in the Engineering Reports over the next two years and the significant majority of the proved undeveloped reserves over the next five years. There are a number of factors that could result in delayed or cancelled development, including the following: (i) changing economic conditions (due to pricing, operating and capital expenditure fluctuations); (ii) changing technical conditions (including production anomalies, such as water breakthrough or accelerated depletion); (iii) multi-zone developments (for instance, a prospective formation completion may be delayed until the initial completion is no longer economic); (iv) a larger development program may need to be spread out over several years to optimize capital allocation and facility utilization; and (v) surface access issues (including those relating to land owners, weather conditions and regulatory approvals).

Proved Undeveloped Reserves

The following table discloses, for each product type, the gross volumes of proved undeveloped reserves that were first attributed, net of conversions and revisions, in each of the most recent three financial years and, in the aggregate, before that time.

Year	Light and Medium Oil (MMbbl)				Heavy Oil (MMbbl)				Natural Gas (Bcf)				NGLs (MMbbl)
	First Attributed		Cumulative at Year End		First Attributed		Cumulative at Year End		First Attributed		Cumulative at Year End		First Attributed		Cumulative at Year End

Prior thereto		21		21		5		5		44		44		1		1
2006		13		33		-		2		8		43		-		1
2007		5		34		1		1		12		38		-		1
2008		9		37		5		6		44		62		-		1

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

For further information, see "Risk Factors".

Probable Undeveloped Reserves

The following table discloses, for each product type, the gross volumes of probable undeveloped reserves that were first attributed, net of conversions and revisions, in each of the most recent three financial years and, in the aggregate, before that time.

Year	Light and Medium Oil (MMbbl)				Heavy Oil (MMbbl)				Natural Gas (Bcf)				NGLs (MMbbl)
	First Attributed		Cumulative at Year End		First Attributed		Cumulative at Year End		First Attributed		Cumulative at Year End		First Attributed		Cumulative at Year End

Prior thereto		12		12		3		3		26		26		1		1
2006		11		22		-		1		7		33		1		2
2007		5		24		1		1		11		26		-		2
2008		11		32		14		13		57		79		1		2

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

Significant Factors or Uncertainties

The development schedule of our undeveloped reserves is based on forecast price assumptions for the determination of economic projects. The actual prices that occur may be significantly lower or higher resulting in some projects being delayed or accelerated, as the case may be. See "Risk Factors".

We do not anticipate that any significant economic factors or other significant uncertainties will affect any particular components of our reserves data. However, our reserves can be affected significantly by fluctuations in product pricing, capital expenditures, operating costs, royalty regimes and well performance that are beyond our control.

Additional Information Concerning Abandonment and Reclamation Costs

Abandonment and reclamation costs in respect of surface leases, wells, facilities and pipelines (collectively, "A&R Costs") are primarily comprised of well bore abandonment and reclamation costs, and liability issues such as flare pit remediation and facility decommissioning, remediation, and reclamation costs. A&R Costs are estimated using our experience conducting annual abandonment and reclamation programs over the past several years.

We review suspended or standing well bores for reactivation, recompletion or sale and conduct systematic abandonment programs for those well bores that do not meet our criteria. A portion of our liability issues are retired every year and facilities are decommissioned when all the wells producing to them have been abandoned. All of our liability reduction programs take into account seasonal access, high priority and stakeholder issues, and opportunities for multi-location programs to reduce costs.

As of December 31, 2008, we expect to incur A&R Costs in respect of approximately 22,288 net well bores and 2,267 facilities. The total amount of A&R Costs, net of estimated salvage values, that we expect to incur, including wells that extend beyond the 50-year limit in the Engineering Reports, are summarized in the following table:

Period	Abandonment and Reclamation Costs Escalated at 2% Undiscounted (MM$)		Abandonment and Reclamation Costs Escalated at 2% Discounted at 10% (MM$)
Total liability as at December 31, 2008		2,679		272

Anticipated to be paid in 2009		45		41
Anticipated to be paid in 2010		47		39
Anticipated to be paid in 2011		49		37

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

OTHER OIL AND GAS INFORMATION

Description of Our Properties, Operations and Activities in Our Major Operating Regions

Introduction

Penn West participates in the exploration for, and the development and production of, oil and natural gas principally in western Canada. Our portfolio of properties as at December 31, 2008 includes both unitized and non-unitized oil and natural gas production. In general, the properties contain long-life, low-decline rate reserves and include interests in several major oil and gas fields. The majority of our proved plus probable reserves are located in Canada in the provinces of Alberta, British Columbia, Saskatchewan and Manitoba, and in the Northwest Territories. We also have minor proved plus probable reserves interests in the United States in the States of Montana, Wyoming and North Dakota.

Major Operating Regions

Our production and reserves are attributed to more than 400 producing properties. No single property accounts for more than 10 percent of our proved plus probable reserves. Penn West's operations are managed based on five major operating regions: (i) Southern District, (ii) Central District, (iii) Eastern District, (iv) NW Alberta District, and (v) Northern District. The following table shows our reported average daily production in 2008 and proved plus probable reserves, as at December 31, 2008, by major operating regions. These major operating regions represented approximately 100 percent of our average daily production in 2008 and approximately 100 percent of our total gross proved plus probable reserves (based on forecast cost and price assumptions) as assigned by GLJ and Sproule in the Engineering Reports.

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

The following map outlines Penn West's five major operating regions as at December 31, 2008:

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

Southern District

The Southern District runs within the southern boundaries of Manitoba, Saskatchewan and Alberta. This district also contains minor operations and land positions in the states of North Dakota, Wyoming and Montana. In 2008, production in this district averaged 39,300 boe/d, comprised of 29,600 bbl/d of crude oil and natural gas liquids and 58 MMcf/d of natural gas.

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

In Southwest Saskatchewan, the predominant play for Penn West is the Leitchville (Lower Shaunavon horizon) tight oil play. This is an unconventional, "resource" play that has been unlocked by multi-stage horizontal fracture technology. In 2008, Penn West drilled 25 wells in the Lower Shaunavon horizon. In 2009, Penn West expects to drill another 20 to 25 wells to further develop and expand the play.

In Southeast Saskatchewan, Penn West has been active on a number of fronts. In 2008, our focus was on land acquisition to increase Penn West's position on the tight oil play in the Bakken pool and to develop a strategy to expand Penn West's knowledge and position on the emerging Torquay play to the eastern edges of the Williston Basin. Also in 2008, we worked on optimization opportunities in Penn West's legacy asset base and participated in the Weyburn unit operated by EnCana Corporation, which is currently under CO2 flood for enhanced oil recovery. Penn West holds a 21% interest in this unit. We plan total capital expenditures of approximately $70 million for Southeast Saskatchewan in 2009.

In Southern Alberta, Penn West drilled 38 wells in 2008, targeting mainly the Colony and Mid-Mannville horizons. In 2009, Penn West plans to drill up to 45 additional wells in Southern Alberta. We plan total capital expenditures of approximately $63 million for Southern Alberta in 2009.

Eastern District

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

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

A major property for Penn West in the Eastern District is Dodsland. In 2008, Penn West drilled its first horizontal injector well in the Dodsland area. In 2009, Penn West plans to drill one additional injector well and two horizontal producer wells in this area. We expect total capital expenditures of approximately $10 million for the Dodsland area in 2009.

Central District

The Central District runs from the eastern border of the Eastern District and stretches from northeast of Edmonton to just north of Calgary and runs west to the foothills of Alberta. This district is Penn West's largest district in terms of production. The district is characterized by legacy light oil assets and gas pools with multi-zone potential. In 2008, production in this district averaged about 65,100 boe/d comprised of 30,700 bbl/d of crude oil and natural gas liquids and 207 MMcf/d of natural gas

As at December 31, 2008, Penn West had a land position of approximately 1.6 million net acres in the Central District. In 2008, Penn West drilled 38 new wells in this district and made a capital investment of approximately $208 million. In 2009, Penn West expects overall capital expenditures to total about $120 million for the Central District.

The Pembina area is a key property for Penn West in the Central District and multi-stage horizontal fracture technology is being used to drill both producing wells and injectors to further enhance recovery in the Pembina area. Penn West has also initiated a CO2 flood pilot project for enhanced oil recovery in the Pembina area and operates at Joffre, Alberta what is currently Alberta's only commercial CO2 flood enhanced oil recovery project. Penn West plans to continue this CO2 flood project in 2009.

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

Another important asset for Penn West in the Central District is the Willesden Green property, which is a legacy asset located west of Red Deer, Alberta. The Willesden Green area is characterized by multi-zone light oil and gas opportunities. In 2008, Penn West drilled a new gas well in the area and in 2009, we plan to acquire seismic in order to identify future drilling locations.

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

NW Alberta District

The NW Alberta District is located north of Edmonton and is bounded by the British Columbia border to the west. This district is predominantly a light oil district characterized by large oil-in-place "legacy assets". Due to the nature of the asset base, Penn West's focus in this district has been on enhanced oil recovery. In 2008, production in this district averaged about 24,500 boe/d, comprised of 18,800 bbl/d of crude oil and natural gas liquids and 34 MMcf/d of natural gas.

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

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

The Swan Hills properties are another important asset for Penn West in the NW Alberta District. The Swan Hills properties are light oil in place "legacy" assets in the Devonian reef complex of the Beaver Hill Lake formation and provide some of Penn West's longest-life reserves. In 2008, Penn West implemented a CO2 flood pilot project for enhanced oil recovery in the South Swan Hills unit, which Penn West operates. In 2009, Penn West plans to evaluate long-term development plans aimed at increasing recovery factors through optimization of current water floods and infill drilling opportunities in the Swan Hills area.

Northern District

The Northern District includes northeastern British Columbia, the northwestern corners of Alberta (including the Peace River Arch) and southwestern Northwest Territories. This district is characterized primarily by natural gas with multi-zone production. In 2008, this district averaged about 28,000 boe/d comprised of 3,900 bbl/d of crude oil and natural gas liquids and 144 MMcf/d of natural gas.

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

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

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

Another important property for Penn West in the Northern District is our position in the Montney natural gas play located near Dawson Creek, British Columbia. In 2009, Penn West plans to drill two horizontal wells and expects total capital expenditures of $10 million for the Montney play.

Additional Information

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

We do not have any material properties to which reserves have been attributed which are capable of producing but which are not producing. For a discussion of our properties to which reserves have been attributed and which are capable of producing but which are not producing, see "Additional Information Relating to Reserves Data – Undeveloped Reserves" above.

Oil And Gas Wells

The following table sets forth the number and status of wells in which we had a working interest as at December 31, 2008.

	Producing								Non-Producing				Total
	Oil				Gas
	Gross		Net		Gross		Net		Gross		Net		Gross		Net

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

Properties with no Attributed Reserves

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

	Unproved Properties (000s of Acres)
	Gross		Net

Alberta		2,208		1,793
British Columbia		756		569
Saskatchewan		755		662
Manitoba		153		147
Northwest Territories		91		18
Wyoming		16		9
Montana		3		2
North Dakota		28		23
Total		4,010		3,223

We currently have no material work commitments on these lands. The primary lease or extension term on approximately 532,323 net acres of unproved property will expire by December 31, 2009. The right to explore, develop and exploit these leases will be surrendered unless we qualify them for continuation based on existing production, drilling or technical mapping.

Tax Horizon

Under currently enacted legislation, as a result of our tax structure, taxable income is transferred from our Operating Entities to the Trust and from the Trust to Unitholders. This is primarily accomplished through the deduction by our Operating Entities of the royalties on underlying oil and gas properties and the deduction of interest on the Internal Notes. The terms of the Trust Indenture require the Trust to distribute all of its taxable income, therefore, it is currently expected that no income tax liability will be incurred provided we maintain this organizational structure. To the extent that taxable income is retained in our Operating Entities to fund capital expenditures or repay bank debt, it is possible that income taxes could be payable at some time in the future.

The legislation implementing the SIFT Tax received Royal assent on June 22, 2007 with the result that commencing January 1, 2011 taxes could be exigible in the Trust as certain distributions will no longer be a deduction in the calculation of its taxable income. For more information on the SIFT Tax, see "General Development of the Business – History and Development – Year Ended December 31, 2006 – Changes to Taxation of Income Trusts" and "Risk Factors".

The most important variables that will determine the level of cash taxes incurred by us in a given year will be the price of crude oil and natural gas, our capital spending levels and the amount of tax pools available to us. Assuming the implementation of the SIFT Tax on January 1, 2011 and that we do not change our current organizational structure, we estimate that we would not be required to pay income taxes until at least the 2014 taxation year. However, if crude oil and natural gas prices were to strengthen beyond the levels anticipated by the current forward market, our tax pools would be utilized more quickly and we may experience higher than expected cash taxes or payment of such taxes in an earlier time period. However, we emphasize that it is difficult to give guidance on future taxability as we operate within an industry where various factors constantly change our outlook, including factors such as acquisitions, divestments, capital spending levels, distribution levels and commodity price changes.

Capital Expenditures

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

	2008 MM$

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

Notes:

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

(2)	Includes equipping and facilities capital expenditures.

Exploration and Development Activities

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

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

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

Production Estimates

The following table sets out the volume of our production estimated for the year ended December 31, 2009 which is reflected in the estimates of gross proved reserves and gross probable reserves disclosed in the tables contained under "Disclosure of Reserves Data" above.

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

No one field accounts for more than three percent of the estimated production disclosed above. For more information, see "Other Oil and Gas Information – Description of Our Properties, Operations and Activities in Our Major Operating Regions".

Production History

The following table summarizes certain information in respect of our production, product prices received, royalties paid, production costs and resulting netback for the periods indicated below:


	Quarter Ended 2008										Year Ended
	Mar. 31			June 30		Sept. 30		Dec. 31			Dec. 31, 2008
Average Daily Production(1)
Light and Medium Crude Oil (bbl/d)		71,560			71,496		68,959		68,219			70,050
Heavy Oil (bbl/d)		27,338			27,460		28,136		26,529			27,366
Gas (MMcf/d)		500			487		500		476			490
NGLs (bbl/d)		10,118			10,461		9,803		10,896			10,320
Combined (boe/d)		192,291			190,515		190,177		184,908			189,462

Average Net Production Prices Received
Light and Medium Crude Oil ($/bbl)		92.07			116.33		114.32		55.02			94.66
Heavy Oil ($/bbl)		66.64			93.12		98.07		38.67			74.55
Gas ($/Mcf)		7.98			10.20		8.49		7.03			8.43
NGLs ($/bbl)		65.43			81.49		83.22		45.53			68.45
Combined ($/boe)		68.35			87.60		83.23		46.79			71.65

Royalties Paid
Light and Medium Crude Oil ($/bbl)		14.34			19.20		19.10		8.70			15.37
Heavy Oil ($/bbl)		9.98			13.50		14.80		5.80			11.09
Gas ($/Mcf)		1.76			2.02		1.89		1.60			1.84
NGLs ($/bbl)		17.30			18.99		21.11		12.57			17.38
Combined ($/boe)		12.25			15.35		15.23		8.89			12.95

Production Costs(2)(3)
Light and Medium Crude Oil ($/bbl)		16.51			16.75		17.79		18.74			17.43
Heavy Oil ($/bbl)		12.87			12.94		13.63		14.04			13.37
Gas ($/Mcf)		1.15			1.19		1.26		1.34			1.23
NGLs ($/bbl)		12.84			13.02		13.84		14.53			13.57
Combined ($/boe)		11.64			11.91		12.49		13.22			12.31

Transportation
Light and Medium Crude Oil ($/bbl)		-			-		-		-			-
Heavy Oil ($/bbl)		0.08			0.06		0.06		0.05			0.06
Gas ($/Mcf)		0.18			0.19		0.18		0.19			0.19
NGLs ($/bbl)		-			-		-		-			-
Combined ($/boe)		0.48			0.49		0.49		0.49			0.49

(Gain)/Loss on Risk Management Contracts
Light and Medium Crude Oil ($/bbl)		9.35			25.26		25.48		(5.91	)		13.64
Heavy Oil ($/bbl)		-			-		-		-			-
Gas ($/Mcf)		(0.03	)		0.99		0.93		(0.37	)		0.39
NGLs ($/bbl)		-			-		-		-			-
Combined ($/boe)		3.41			12.01		11.69		(3.12	)		6.05


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

Notes:

(1)	Before deduction of royalties.

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

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

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

Marketing Arrangements

Our marketing approach incorporates the following primary objectives:

·	Ensure security of market and avoid production shut-ins due to marketing constraints by dealing with end-users or regionally strategic counterparties wherever possible.

·	Ensure protection of our receivables by dealing only with credit worthy counterparties who have been subjected to regular credit reviews.

·	Ensure competitive pricing by managing pricing exposures through a portfolio of various terms and geographic basis.

·	Ensure optimization of netbacks through careful management of transportation obligations, facility utilization levels, blending opportunities and emulsion handling.

Natural Gas Marketing

In 2008, we received an average price from the sale of natural gas, before adjustments for hedging activities, of $8.43/Mcf compared to $6.85/Mcf realized in 2007. Approximately 87 percent of our natural gas sales are marketed directly with the balance of natural gas sales marketed in aggregator pools. We continue to maintain a significant weighting to the Alberta market as this market offers a premium netback relative to most other indices. In addition to maximizing netbacks, the current portfolio approach also enhances our operational flexibility to pursue higher netback opportunities as they become available.

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

Oil and Liquids Marketing

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

To reduce risk, we market the majority of our production at the lease level on varying term contracts and actively manage our heavy oil supply by finding opportunities to optimize netbacks through blending, trucking and proprietary handling of emulsion. Blending costs are also controlled through the use of proprietary condensate supply.

The following table summarizes the net product price received for our production of conventional light and medium oil (including NGLs) and our conventional heavy oil, before adjustments for hedging activities, for the periods indicated:

	2008				2007
	Light and Medium Oil		Heavy Oil		Light and Medium Oil		Heavy Oil
Quarter ended	($/bbl)		($/bbl)		($/bbl)		($/bbl)

March 31		92.07		66.64		60.93		41.03
June 30		116.33		93.12		66.57		42.45
September 30		114.32		98.07		74.49		48.75
December 31		55.02		38.67		78.20		48.69

Forward Contracts

We are exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of operations. In accordance with policies approved by our Board of Directors, we may, from time to time, manage these risks through the use of swaps, collars or other financial instruments. Commodity price risk may be hedged up to a maximum of 50 percent of forecast sales volumes, net of royalties, for the balance of any current year and one year following and up to 25 percent of forecast sales volumes, net of royalties, for one additional year thereafter. This policy is reviewed by management and our Board of Directors from time to time and amended as necessary.

We are also exposed to losses in the event of default by the counterparties to these derivative instruments. We manage this risk by diversifying our hedging portfolio among a number of financially sound counterparties. For information in relation to marketing arrangements, see "Other Oil and Gas Information – Marketing Arrangements".

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

Our transportation obligations and commitments for future physical deliveries of crude oil and natural gas do not exceed our expected related future production from our proved reserves, estimated using forecast prices and costs.

APPENDIX B

MANDATE OF 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 West Energy Trust (the "Trust"), to which the board has delegated its responsibility for oversight of the integrity of the Trust's consolidated financial statements, the Trust's compliance with legal and regulatory requirements, the independent auditor's qualifications and independence, and the performance of the Trust's internal audit function, if any. The objectives of the Committee, with respect to Company and the Trust (hereinafter collectively referred to as "Penn West"), are as follows:

·	To assist the Board in meeting its responsibilities (especially for accountability) in respect of the preparation and disclosure of the consolidated financial statements of the Trust and related matters;

·	To provide better communication between directors and independent auditors;

·	To assist the Board in meeting its responsibilities regarding the oversight of the independent auditor's qualifications and independence;

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

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

·	To assist the Board in meeting its responsibilities regarding the oversight of the performance of the Company's independent auditors and internal audit function, if any; and

·	To assist the Board in meeting its responsibilities regarding the oversight of the Company's compliance with legal and regulatory requirements.

Mandate and Responsibilities of Committee

·	It is the responsibility of the Committee to satisfy itself on behalf of the Board that the Company's internal control systems are sufficient to reasonably ensure that:

·	controllable, material business risks are identified, monitored and mitigated where it is determined cost effective to do so;

·	internal controls over financial reporting are sufficient to meet the requirements under National Instrument 52-109 and the United States Securities Exchange Act of 1934, as amended; and

·	legal, ethical and regulatory requirements are complied with.

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

·	reviewing changes in accounting principles, or in their application, which may have a material impact on the current or future years' financial statements;

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

·	reviewing accounting treatment of unusual or non-recurring transactions;

·	reviewing the Trust's status as a "mutual fund trust" under the Income Tax Act (Canada);

·	ascertaining compliance with covenants under loan agreements and Trust Indenture;

·	reviewing adequacy of the asset retirement obligations;

·	reviewing disclosure requirements for commitments and contingencies;

·	reviewing adjustments raised by the independent auditors, whether or not included in the financial statements;

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

·	obtaining reasonable explanations of significant variances with comparative reporting periods; and

·	determine through inquiry if there are any related party transactions and ensure the nature and extent of such transactions are properly disclosed.

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

Discuss the Trust's quarterly results press releases, as well as financial information and earnings guidance provided to analysts and rating agencies (provided that the Committee is not required to review and discuss investor presentations that do not contain financial information or earnings guidance that has not previously been generally disclosed to the public).

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

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

be directly responsible for appointing, compensating, retaining and overseeing the work of the independent auditors engaged for the purpose of issuing an auditors' report or performing other audit, review or attest services for the Trust, including the resolution of disagreements between management and the independent auditor regarding financial reporting, and the independent auditors shall report directly to the Committee;

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

·	review the basis of management's recommendation for the appointment of independent auditors and recommend to the board appointment of independent auditors and their compensation;

·	review the terms of engagement and the overall audit plan (including the materiality levels to be applied) of the independent auditors, including the appropriateness and reasonableness of the auditors' fees;

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

·	review and pre-approve any audit and permitted non-audit services to be provided by the independent auditors' firm and consider the impact on the independence of the auditors.

At least annually, obtaining and reviewing the report by the independent auditors describing the independent auditors' internal quality control procedures, any material issues raised by the most recent interim quality-control review, or peer review, of the independent auditors, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the independent auditors, and any steps taken to deal with any such issues.

Review with the independent auditors (and internal auditors, if any) their assessment of the internal controls of the Company, their written reports containing recommendations for improvement, and management's response and follow-up to any identified weaknesses. The Committee shall also review annually with the independent auditors

their plan for their audit and, upon completion of the audit, their reports upon the financial statements of Penn West and its subsidiaries.

At least annually, obtaining and reviewing a report by the independent auditors describing (i) all critical accounting policies and practices used by the Trust, (ii) all alternative accounting treatments of financial information within generally accepted accounting principles related to material items that have been discussed with management, including the ramifications of the use of such alternative treatments and disclosures and the treatment preferred by the accounting firm, and (iii) other material written communications between the accounting firm and management of Penn West.

·	Obtain assurance from the independent auditors that disclosure to the Committee is not required pursuant to the provisions of the United States Securities Exchange Act of 1934, as amended, regarding the discovery by the independent auditors of illegal acts.

Pre-approve the completion of any audit and permitted non-audit services by the independent auditors and determine which non-audit services the independent auditor is prohibited from providing. The Committee may delegate to one or more members of the Committee authority to pre-approve non-audit services in satisfaction of this requirement and if such delegation occurs, the pre-approval of non-audit services by the Committee member to whom authority has been delegated must be presented to the Committee at its first scheduled meeting following such pre-approval. The Committee shall be entitled to adopt specific policies and procedures for the engagement of non audit services if:

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

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

·	the procedures do not include delegation of the Committee's responsibilities to management.

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

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

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

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

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

·	Review all public disclosure containing financial information before release (provided that the Committee is not required to review investor presentations that do not contain financial information or earnings guidance that has not previously been generally disclosed to the public).

·	Review all pending litigation to ensure disclosures are sufficient and appropriate.

·	Satisfy itself that adequate procedures are in place for the review of the Trust's public disclosure of financial information from the Trust's financial statements and periodically assess the adequacy of those procedures.

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

·	Establish procedures independent of management for:

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

·	the confidential, anonymous submission by employees of the Trust of concerns regarding questionable accounting or auditing matters.

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

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

·	Review management's monitoring of the Trust's compliance with the organization's Code of Business Conduct and Ethics and the Code of Conduct for Senior Officers and Senior Financial Management.

Review and discuss with the Chief Executive Officer, the Chief Financial Officer and the independent auditors, the matters required to be reviewed with those persons in connection with any certificates required by applicable laws, regulations or stock exchange requirements to be provided by the Chief Executive Officer and Chief Financial Officer.

·	Review and discuss major issues regarding accounting principles and financial statement presentations, including any significant changes in the Trust's selection or application of accounting principles.

·	Review and discuss major issues as to the adequacy of the Trust's internal controls and any special audit steps adopted in light of material control deficiencies.

Review and discuss analyses prepared by management and/or the independent auditors setting forth significant financial reporting issues and judgments made in connection with the preparation of the financial statements, including analyses of the effects of alternative generally accepted accounting principles methods on the financial statements.

·	Review and discuss the effect of regulatory and accounting initiatives, as well as off-balance sheet structures, on the Trust's financial statements.

·	Review and discuss the type and presentation of information to be included in earnings press releases, paying particular attention to any use of "pro forma" or "adjusted" non-GAAP information.

Composition

This Committee shall be composed of at least three individuals appointed by the Board from amongst its members, all of which members will be independent (within the meaning of (a) National Instrument 52-110 Audit Committees and (b) Sections 303A.02 and 303A.07(b) of the Corporate Governance Rules of the New York Stock Exchange) unless the Board determines to rely on an exemption in National Instrument 52-110.

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

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

All of the members must be financially literate within the meaning of National Instrument 52-110 and Section 303A.07(a) of the Corporate Governance Rules of the New York Stock Exchange unless the Board has determined to rely on an exemption in National Instrument 52-110. Being "financially literate" means members have the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be

raised by the Trust's financial statements. In addition, at least one member of the Committee must have accounting or related financial management expertise, as the Board interprets such qualification in its business judgment.

In connection with the appointment of the members of the Committee, the Board will determine whether any proposed nominee for the Committee serves on the audit committee of more than three public companies. To the extent that any proposed nominee of PWPL serves on the audit committee of more than three public companies, the Board will make a determination as to whether such simultaneous services would impair the ability of such member to effectively serve on the Company's Audit Committee and will disclose such determination in the Trust's annual information circular and annual report on Form 40-F filed with the Securities and Exchange Commission.

Meetings

The Committee shall meet at least four times per year and/or as deemed appropriate by the Committee Chair. As part of its job to foster open communication, the Committee should meet at least annually with management, internal auditors (if any) and the independent auditors in separate executive sessions to discuss any matters that the Committee or each of these groups believe should be discussed privately. In addition, the Committee or at least its Chair should meet with the independent auditors and management quarterly to review the Trust's financials. The Committee should also meet with management and independent auditors on an annual basis to review and discuss annual financial statements and the management's discussion and analysis of financial conditions and results of operations.

·	Agendas, with input from management, shall be circulated to Committee members and relevant management personnel along with background information on a timely basis prior to the Committee meetings.

·	Minutes of each meeting shall be prepared by the Secretary to the Committee.

·	The Chief Executive Officer and the Chief Financial Officer or their designates shall be available to attend at all meetings of the Committee upon the invitation of the Committee.

·	The Vice President, Accounting & Reporting and the Vice President, Treasury & Compliance and such other staff as appropriate to provide information to the Committee shall attend meetings upon invitation by the Committee.

Reporting / Authority

At the first Board meeting following a Committee meeting, the Committee will provide a verbal report to the Board of the material matters discussed and material resolutions passed at the Committee meeting. The draft minutes of the Committee meeting will subsequently be provided to all Board members as soon as practicable.

·	Supporting schedules and information reviewed by the Committee shall be available for examination by any Director.

·	The Committee shall have the authority to investigate any financial activity of the Trust and to communicate directly with the internal (if any) and independent auditors. All employees are to cooperate as requested by the Committee.

·	The Committee may retain, and set and pay the compensation for, persons having special expertise and/or obtain independent professional advice, including the engagement of independent counsel and other advisors, to assist in fulfilling its duties and responsibilities at the expense of Penn West.

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

·	The Committee, in its capacity as a committee of the Board, shall determine appropriate funding and cause such funding to be available (i) to Penn West's independent auditors for the purpose of preparing and issuing an audit

report, (ii) to any advisors employed by the Committee, and (iii) for ordinary administration expenses of the Committee that are necessary or appropriate in carrying out its duties.

Exhibit	Description

99.1	Revised Annual Information Form for the fiscal year ended December 31, 2008

99.2*	Management’s Discussion and Analysis of Financial Condition and Results of Operations for the fiscal year ended December 31, 2008

99.3*	Consolidated Financial Statements for the fiscal year ended December 31, 2008

99.4*	Supplemental Note to the Consolidated Financial Statements relating to the reconciliation of Canadian and United States Generally Accepted Accounting Principles

99.5	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934

99.6	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934

99.7*	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350

99.8*	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350

99.9*	Consent of KPMG LLP

99.10*	Consent of GLJ Petroleum Consultants Ltd.

99.11*	Consent of Sproule Associates Limited